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PG&E CORP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF OPERATIONS

Source: 
Edgar Glimpses

OVERVIEW

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility's electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility's electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility's nuclear generation facilities. The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

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

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation's and the Utility's Chapter 11 Cases were jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). On the Effective Date, PG&E Corporation and the Utility emerged from Chapter 11. For additional information regarding the Chapter 11 Cases, refer to the website maintained by Prime Clerk, LLC, PG&E Corporation's and the Utility's claims and noticing agent, at http://restructuring.primeclerk.com/pge. The contents of this website are not incorporated into this document. For more information about Chapter 11 emergence and related transactions, see the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Chapter 11 Emergence and Going Concern

The accompanying Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection (see Note 10 of the Notes to the Condensed Consolidated Financial Statements for additional information). Uncertainty regarding these matters previously raised substantial doubt about PG&E Corporation's and the Utility's abilities to continue as going concerns. As a result of PG&E Corporation's and the Utility's emergence from Chapter 11 on July 1, 2020, substantial doubt has been alleviated regarding the Company's ability to meet its obligations as they become due within one year after the date of the accompanying Condensed Consolidated Financial Statements. For more information regarding the Chapter 11 Cases, see Note 2 of the Notes to the Condensed Consolidated Financial Statements. For more information about Chapter 11 emergence and related transactions, see the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q. 82 --------------------------------------------------------------------------------

Tax Matters

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

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

In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation's common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility paid to the Fire Victim Trust 477 million shares of PG&E Corporation's common stock. Because of the price of the stock on the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.22 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation's shares to the Fire Victim Trust. In addition, this deferred tax asset reflects PG&E Corporation's conclusion as of June 30, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a "qualified settlement fund" for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. As discussed further below in the Risk Factors section, PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a "grantor trust," but only if PG&E Corporation receives favorable determinations from the IRS regarding certain aspects of such election. If PG&E Corporation makes a "grantor trust" election for the Fire Victim Trust, the Utility's tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be based on the price at which the Fire Victim Trust sells the shares. In this case, the accounting treatment will require a re-evaluation under applicable accounting guidance of the remaining deferred tax asset and could result in a further impairment thereof or other material impact on the Condensed Consolidated Financial Statements. Additionally, the value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust is treated as a "qualified settlement fund."

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation's net loss attributable to common shareholders was $1,972 million and $1,601 million in the three and six months ended June 30, 2020, respectively, compared to net losses of $2,553 million and $2,420 million in the same periods in 2019. PG&E Corporation recognized charges of $1.9 billion and $2.0 billion, net of probable insurance recoveries, associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019, as compared to a charge of $170 million, net of probable insurance recoveries related to the 2019 Kincade fire in the three and six months ended June 30, 2020. Additionally, in the three and six months ended June 30, 2020, PG&E Corporation recognized $1.1 billion of expense related to the Backstop Commitment premium and $444 million of expense related to the Additional Backstop Premium Shares, with no similar amounts for the same periods in 2019. 83 --------------------------------------------------------------------------------

Key Factors Affecting Financial Results

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

•The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. Although the financial impact of future wildfires could be mitigated through insurance, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. In July 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $757.5 million (subject to an initial self-insured retention of $60 million), comprised of $715 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. 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 and the Utility continue to pursue additional insurance coverage for the period from August 1, 2020 through July 31, 2021. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any calendar year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund would be available to the Utility to pay eligible claims for liabilities arising from future wildfires and would serve as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility's ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility's ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility's emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims will be capped at 40% of the amount of such claims. •The Uncertainties Regarding the Impact of Public Safety Power Shutoffs. The Utility's wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility's wildfire risk mitigation initiatives outlined in the 2019 Wildfire Mitigation Plan, has been the subject of significant scrutiny and criticism by various stakeholders, including the California Governor, the CPUC and the court overseeing the Utility's probation. On November 12, 2019, the CPUC issued an order to show cause why the Utility should not be sanctioned for alleged violations of law related to its communications with customers, coordination with local governments, and communications with critical facilities and public safety partners during the PSPS events in late 2019. On November 13, 2019, the CPUC instituted an OII to examine 2019 PSPS events carried out by California's investor-owned utilities and to consider enforcement actions. In addition, the PSPS program has had an adverse impact on PG&E Corporation's and the Utility's reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. In addition to the 2019 PSPS events, the Utility expects that PSPS events will be necessary in 2020 and future years. (See "OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions" in "Regulatory Matters" below.) 84 -------------------------------------------------------------------------------- In addition, the proposals of SB 378, which would impose penalties and other requirements on electric utility companies relating to PSPS events, 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 to other requirements, SB 378 would impose on an electric utility company a civil penalty of at least $250,000 per 50,000 affected customers for every hour that a PSPS event is in place, would require the CPUC to establish a procedure for customers, local governments and others to recover costs accrued during a PSPS event from the electric utility company, which cost recovery would be borne by shareholders, and would prohibit an electric utility company from billing customers for any nonfixed costs during a PSPS event. Further, the proposals of AB 1941 could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. AB 1941 proposes to suspend RPS requirements, determine the savings to electric utility companies from the suspension and direct those savings towards system hardening to mitigate wildfire risks and PSPS impacts, and would prohibit salary increases or bonuses to executive officers during the suspension of RPS requirements. In addition, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The requested requirements include providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. A CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events. PG&E Corporation and the Utility are unable to predict the timing and the outcome of this request. •The Costs of Other Wildfire Mitigation Efforts. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events. PG&E Corporation and the Utility incurred approximately $2.6 billion in connection with the 2019 WMP and expect to incur approximately $2.6 billion in 2020 in connection with its 2020-2022 WMP. Although the Utility may seek cost recovery for certain of these expenses and capital expenditures, the Utility has agreed not to seek rate recovery of certain wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion. While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows. The Court overseeing the Utility's probation in connection with the Utility's federal criminal proceeding has imposed numerous obligations on the Utility related to its business and operations. Such obligations include full compliance with all applicable laws concerning vegetation management and clearance requirements, submission to regular, unannounced inspections by the Monitor of the Utility's vegetation management efforts and equipment inspections, enhancement and repair efforts, the maintenance of traceable, verifiable, accurate and complete records of the Utility's vegetation management efforts and monthly reports to the Monitor on the status and progress of vegetation management efforts. On April 29, 2020, the Court entered an additional order requiring, among other things, the Utility to materially expand its vegetation management program, including through the hiring of additional employees, and to implement a new inspection and record-keeping system for transmission towers. The April 29, 2020 order is currently stayed, pending further review by the Court. (See "U.S. District Court Matters and Probation" in "Enforcement and Litigation Matters" below.) PG&E Corporation and the Utility also face uncertainties in connection with the amount and recoverability of enhanced and accelerated inspection costs of the Utility's electric transmission and distribution assets. (See "Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire" in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) •The Timing and Outcome of Ratemaking Proceedings. The Utility's financial results may be impacted by the timing and outcome of its 2020 GRC, FERC TO18, TO19, and TO20 rate cases, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, FHPMA, WMPMA, FRMMA, and CPPMA. The outcome of regulatory proceedings can be affected by many factors, including intervening parties' testimonies, potential rate impacts, the Utility's reputation, the regulatory and political environments, and other factors. The Utility's ability to seek cost recovery will also be limited by the outcome of the Wildfires OII. (See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and "Regulatory Matters" below.) 85 -------------------------------------------------------------------------------- •The Impact of the 2019 Kincade Fire. Claims related to the 2019 Kincade fire will not be discharged in connection with emerging from Chapter 11. On July 16, 2020, Cal Fire issued a press release stating that it had determined that "the Kincade fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E)." Accordingly, if PG&E Corporation or the Utility were determined to be liable for the 2019 Kincade fire, such liabilities could be significant and could exceed the amounts available under applicable insurance policies, which could be expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows. For the three months ended June 30, 2020, PG&E Corporation and the Utility recorded a loss of $600 million for the 2019 Kincade fire, which amount corresponds to the lower end of the range of reasonably estimable probable losses. 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 a 40% cap on the amount of such claim. As of June 30, 2020, the Utility has also recorded an insurance receivable for $430 million. See "2019 Kincade Fire" in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information. •The Impact of the COVID-19 pandemic. 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 by the outbreak of COVID-19. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility's customers, the moratorium on service disconnections and an observed reduction in non-residential electrical load. The Utility 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. This impact to liquidity may be partially offset by reductions in discretionary capital spending or potential regulatory or payroll tax policy changes. As of July 1, 2020, PG&E Corporation and the Utility had access to approximately $2.8 billion of total liquidity comprised of approximately $174 million of Utility cash, $343 million of PG&E Corporation cash and $2.3 billion of availability under the Utility and PG&E Corporation credit facilities. Other potential impacts of COVID-19 on PG&E Corporation and the Utility include operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility's operations may also adversely impact operations, a reduction in revenue due to the cost of capital adjustment mechanism, the potential for higher credit spreads and borrowing costs and incremental financing needs. For more information on the impact of COVID-19 on PG&E Corporation and the Utility, see "PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows could be significantly affected by the outbreak of the COVID-19 pandemic" in Item 1A Risk Factors in Part II.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. PG&E Corporation and the Utility continue to evaluate the overall impact of COVID-19 and their analysis is subject to change.

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility's financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the safety culture OII, the sentencing terms of the Utility's January 27, 2017 federal criminal conviction, including the oversight of the Utility's probation and the potential recommendations by the Monitor, and potential penalties in connection with the Utility's safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) In addition, the Utility's business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility's businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California. Further, certain parties filed notices of appeal with respect to the Confirmation Order, including provisions related to the injunction contained in the Plan that channels certain pre-petition fire-related claims to trusts to be satisfied from the trusts' assets. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility. 86 -------------------------------------------------------------------------------- •The Utility's Compliance with the CPUC Capital Structure. The CPUC's capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more. Subsequently, on June 1, 2020 the CPUC issued a decision in the Chapter 11 Proceedings OII granting 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, and also directed the Utility to file an Advice letter annually informing the Commission of its current capital structure and deviation from its authorized capital structure, an updated annual forecast for de-leveraging, and its current credit ratings for secured and unsecured debt. (See "Regulatory Matters" below.) For more information about the risks that could materially affect PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see "Item 1A. Risk Factors" in this Form 10-Q and the 2019 Form 10-K. In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management's judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. See the section entitled "Forward-Looking Statements" above for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS

The following discussion presents PG&E Corporation's and the Utility's operating results for the three and six months ended June 30, 2020 and 2019. See "Key Factors Affecting Financial Results" above for further discussion about factors that could affect future results of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the "Utility" section below. The following table provides a summary of net income (loss) attributable to common shareholders for the three and six months ended June 30, 2020 and 2019: Six Months Ended June Three Months Ended June 30, 30, (in millions) 2020 2019 2020 2019 Consolidated Total $ (1,972) $ (2,553) $ (1,601) $ (2,420) PG&E Corporation (1,495) 1 (1,572) 4 Utility $ (477) $ (2,554) $ (29) $ (2,424) PG&E Corporation's net income (loss) primarily consists of income taxes, interest income on cash held, interest expense on long-term debt, reorganization items, net, and approximately $1.5 billion in expense related to the Backstop Commitment premium and Additional Backstop Premium Shares in the second quarter of 2020, which is not deductible for tax purposes.

Utility

The table below shows certain items from the Utility's Condensed Consolidated Statements of Income for the three and six months ended June 30, 2020 and 2019. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as energy procurement costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings. 87 -------------------------------------------------------------------------------- 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. Three Months Ended Three Months Ended June 30, 2020 June 30, 2019 Revenues/Costs: Revenues/Costs: That Impacted That Did Not That Impacted That Did Not (in millions) Earnings Impact Earnings Total Utility Earnings Impact Earnings Total Utility Electric operating revenues $ 2,303 $ 1,132 $ 3,435 $ 1,872 $ 1,074 $ 2,946 Natural gas operating revenues 832 266 1,098 792 205 997 Total operating revenues 3,135 1,398 4,533 2,664 1,279 3,943 Cost of electricity - 759 759 - 837 837 Cost of natural gas - 134 134 - 108 108 Operating and maintenance 1,596 549 2,145 1,562 378 1,940 Wildfire-related claims, net of insurance recoveries 170 - 170 3,900 - 3,900 Wildfire fund expense 173 - 173 - - - Depreciation, amortization, and decommissioning 874 - 874 796 - 796 Total operating expenses 2,813 1,442 4,255 6,258 1,323 7,581 Operating income (loss) 322 (44) 278 (3,594) (44) (3,638) Interest income 12 - 12 22 - 22 Interest expense (189) - (189) (60) - (60) Other income, net 49 44 93 20 44 64 Reorganization items (111) - (111) (57) - (57) Income (loss) before income taxes $ 83 $ - $ 83 $ (3,669) $ - $

(3,669)

Income tax provision (benefit) (1) 556 (1,119) Net loss (473) (2,550) Preferred stock dividend requirement (1) 4 4 Loss Attributable to Common Stock $ (477) $

(2,554)

(1) These items impacted earnings for the three months ended June 30, 2020 and 2019.

88 -------------------------------------------------------------------------------- Six Months Ended June 30, 2020

Six Months Ended June 30, 2019

Revenues/Costs: Revenues/Costs: That Impacted That Did Not That Impacted That Did Not (in millions) Earnings Impact Earnings Total Utility Earnings Impact Earnings Total Utility Electric operating revenues $ 4,459 $ 2,016 $ 6,475 $ 3,786 $ 1,952 $ 5,738 Natural gas operating revenues 1,696 668 2,364 1,586 630 2,216 Total operating revenues 6,155 2,684 8,839 5,372 2,582 7,954 Cost of electricity - 1,304 1,304 - 1,436 1,436 Cost of natural gas - 418 418 - 447 447 Operating and maintenance 3,059 1,051 4,110 3,256 788 4,044 Wildfire-related claims, net of insurance recoveries 170 - 170 3,900 - 3,900 Wildfire fund expense 173 - 173 - - - Depreciation, amortization, and decommissioning 1,729 - 1,729 1,593 - 1,593 Total operating expenses 5,131 2,773 7,904 8,749 2,671 11,420 Operating income (loss) 1,024 (89) 935 (3,377) (89) (3,466) Interest income 28 - 28 43 - 43 Interest expense (441) - (441) (161) - (161) Other income, net 97 89 186 41 89 130 Reorganization items (204) - (204) (168) - (168) Income (loss) before income taxes $ 504 $ - $ 504 $ (3,622) $ - $ (3,622) Income tax provision (benefit) (1) 526 (1,205) Net loss (22) (2,417) Preferred stock dividend requirement (1) 7 7 Loss Attributable to Common Stock $ (29)

$ (2,424)

(1) These items impacted earnings for the six months ended June 30, 2020 and 2019.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility's operating results for the three and six months ended June 30, 2020 and 2019, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility's electric and natural gas operating revenues that impacted earnings increased by $471 million, or 18%, and $783 million, or 15%, in the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019, primarily due to additional revenue recorded pursuant to the pending TO20 rate case. Operating and Maintenance The Utility's operating and maintenance expenses that impacted earnings decreased by $34 million or 2% in the three months ended June 30, 2020, compared to the same period in 2019, due to a decrease in costs relating to enhanced and accelerated inspections and repairs of transmission and distribution assets of approximately $270 million in the three months ended June 30, 2020, compared to the same period in 2019. In addition, clean-up and repair costs relating to the 2018 Camp fire decreased by $71 million in the three months ended June 30, 2020, compared to the same period in 2019. These decreases were partially offset by $35 million in clean-up and repair costs related to the 2019 Kincade fire, $45 million in costs related to the Wildfire OII settlement, as modified by the Decision Different, and increased labor and insurance costs in the three months ended June 30, 2020, compared to the same period in 2019. 89 -------------------------------------------------------------------------------- The Utility's operating and maintenance expenses that impacted earnings decreased by $197 million, or 6%, in the six months ended June 30, 2020, compared to the same period in 2019, primarily due to a decrease in costs relating to enhanced and accelerated inspections and repairs of transmission and distribution assets of approximately $470 million in the six months ended June 30, 2020, compared to the same period in 2019. In addition, clean-up and repair costs relating to the 2018 Camp fire decreased by $250 million in the six months ended June 30, 2020, compared to the same period in 2019. These decreases were partially offset by $20 million in restoration and rebuild costs related to the 2018 Camp fire, $35 million in clean-up and repair costs related to the 2019 Kincade fire, $61 million in costs related to the Wildfire OII settlement, as modified by the Decision Different, and increased labor, contract, insurance, and benefits costs in the six months ended June 30, 2020, compared to the same period in 2019.

Wildfire-related claims, net of insurance recoveries

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

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

Wildfire fund expense

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

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

Depreciation, Amortization, and Decommissioning

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

Interest Income

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

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

Other Income, Net

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

Reorganization items, net

Reorganization items, net increased by $54 million, or 95% in the three months ended June 30, 2020 compared to the same period in 2019 primarily due to an increase of $34 million of expenses directly associated with the Utility's Chapter 11 filing and a decrease in interest income of $18 million.

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

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

Income Tax Benefit

Income tax benefit decreased by $1.68 billion, or 150%, and $1.73 billion, or 144%, in the three and six months ended June 30, 2020, respectively, as compared to the same periods in 2019, primarily due to a pre-tax loss in 2019 compared to pre-tax income in 2020 and a write-off of a deferred tax asset associated with PG&E Corporation stock contributed into a Fire Victim Trust. For more information on the tax treatment of contributions to the Fire Victim Trust, see "Tax Matters" above.

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

Six Months Ended June Three Months Ended June 30, 30, 2020 2019 2020 2019 Federal statutory income tax rate 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) 228.4 % 7.4 % 38.5 % 7.7 % Effect of regulatory treatment of fixed asset differences (2) (85.9) % 2.3 % (37.9) % 4.6 % Bankruptcy and Emergence (3) 519.7 % - 86.7 % - % Other, net (14.9) % (0.2) % (4.0) % - % Effective tax rate 668.3 % 30.5 % 104.3 % 33.3 % (1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation's and the Utility's effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2020 and 2019, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) Includes an adjustment of the measurement of the deferred tax asset associated with the difference between the accrual and the value of PG&E stock contributed to the Fire Victim Trust.

Utility Revenues and Costs that Did Not Impact Earnings

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

Cost of Electricity

The Utility's cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California's cap-and-trade program, and realized gains and losses on price risk management activities. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility's total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility's own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity. Six Months Ended June Three Months Ended June 30, 30, (in millions) 2020 2019 2020 2019 Cost of purchased power, net (1) $ 712 $ 796 $ 1,185 $ 1,295 Fuel used in generation facilities 47 41 119 141 Total cost of electricity $ 759 $ 837 $ 1,304 $ 1,436 (1) Cost of purchased power, net decreased for the three and six months ended June 30, 2020, compared to the same periods in 2019, primarily due to lower Utility electric customer demand, driven by customer departures to CCAs and DA providers, and by higher net sales in the CAISO electricity markets. 91 --------------------------------------------------------------------------------

Cost of Natural Gas

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. Three Months Ended June 30, Six Months Ended June 30, (in millions) 2020 2019 2020 2019 Cost of natural gas sold $ 102 $ 82 $ 355 $ 391 Transportation cost of natural gas sold 32 26 63 56 Total cost of natural gas $ 134 $ 108 $ 418 $ 447

Operating and Maintenance Expenses

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

Other Income, Net

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.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

As a result of PG&E Corporation's and the Utility's emergence from Chapter 11 on July 1, 2020, substantial doubt has been alleviated regarding the Company's ability to meet its obligations as they become due within one year after the date of the accompanying Condensed Consolidated Financial Statements. Upon the Effective Date, the Utility's ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility's capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceeding OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility's exit from Chapter 11. PG&E Corporation's ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility, depends on the level of cash on hand, cash distributions received from the Utility, and PG&E Corporation's access to the capital and credit markets. In 2019, as a result of the initiation of the Chapter 11 Cases, each of Moody's, Fitch, and S&P withdrew its credit ratings for PG&E Corporation and the Utility. As a result of PG&E Corporation's and the Utility's credit ratings ceasing to be rated at investment grade, the Utility was required to post collateral under certain of its commodity purchase agreements and certain other obligations. On June 15, 2020, the agencies re-commenced rating the Utility and PG&E Corporation. The Utility and PG&E Corporation were assigned Ba2, BB, and BB- as their issuer credit ratings by Moody's, Fitch, and S&P, respectively. Additionally, Moody's assigned a B1 rating to PG&E Corporation's Senior Secured debt, a Baa3 rating to the Utility's Senior Secured debt, and a B1 rating to the Utility's preferred stock. Fitch assigned a BB rating to PG&E Corporation's Senior Secured debt, a BBB- rating to the Utility's Senior Secured debt, and a BB rating to the Utility's preferred stock. Lastly, S&P assigned a BB- and BBB- rating to PG&E Corporation's and the Utility's Senior Secured debt, respectively. 92 -------------------------------------------------------------------------------- As of the Effective Date, PG&E Corporation and the Utility had access to approximately $2.8 billion of total liquidity comprised of approximately $174 million of Utility cash, $343 million of PG&E Corporation cash and $2.3 billion of availability under the Utility and PG&E Corporation credit facilities. Due to the timing of payments made in accordance with the terms of the Plan, on July 1, 2020, the Utility borrowed $775 million on its revolving credit facility. The $775 million was repaid in full by July 17, 2020. As a result of the outbreak of COVID-19, PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows could continue to be significantly affected. The Utility continues to evaluate the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist, including the moratorium on service disconnections and an observed reduction in non-residential electrical load. The reduction in cash collections from customers may be partially offset by reductions in discretionary capital spending or potential regulatory or payroll tax policy changes. The outbreak of COVID-19 and the resulting economic conditions and government orders have and will continue to have a significant adverse impact on the Utility's customers and, as a result, these circumstances have and will continue to impact the Utility for an indeterminate period of time. Although the Utility is seeking regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance that any relief is forthcoming or that, if any relief measures are implemented, the timing that any such relief would impact the Utility. On April 16, 2020, the CPUC approved a resolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the customer protections described within the resolution. On May 1, 2020, the Utility filed an advice letter with the CPUC, 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 and is pending CPUC approval. (See "Emergency Authorization and Resolution Directing Utilities to Implement Emergency Customer COVID-19 Protections" below for more information.) Cash and Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, PG&E Corporation and the Utility hold restricted cash that primarily consists of cash held in escrow pending the resolution of claims under the Plan.

Financial Resources

DIP Credit Agreement

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

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

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

On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.

Equity Financings

On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. During the six months ended June 30, 2020, there were no issuances under this agreement. Beginning January 1, 2019, PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation's directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation. 93 -------------------------------------------------------------------------------- In connection with its emergence from Chapter 11, in July 2020, PG&E Corporation issued for gross proceeds of approximately $9.0 billion (i) 423.4 million shares of common stock in the Common Stock Offering, (ii) 342.1 million shares of common stock pursuant to the Investment Agreement, (iii) forward stock purchase contracts to the Backstop Parties pursuant to the Forward Stock Purchase Agreement and (iv) 14.5 million Equity Units in the Equity Unit Offering, representing the right to receive, on maturity, between 125 million and 153 million shares of PG&E Corporation common stock. Such gross proceeds were used to fund distributions under the Plan. For more information, see Note 6 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

Debt Financings

Utility

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

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

On the Effective Date, pursuant to the Plan, the Utility reinstated $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility's delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first lien, subject to permitted liens, on substantially all of the Utility's real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility's senior obligations and rank equally in right of payment with the Utility's other existing or future first mortgage bonds issued under the Utility's mortgage indenture. On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated. In addition, on July 1, 2020, the Utility obtained a $1.5 billion 364-day and a $1.5 billion 18-month secured term loan under a term loan credit agreement. For more information, see "Credit Facilities" discussion below.

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

PG&E Corporation

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan under a term loan credit agreement. The Term Loan matures on the date that is five years after June 23, 2020, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The proceeds of the Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation. On the July 1, 2020, the net proceeds from the Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan. 94 -------------------------------------------------------------------------------- Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (collectively, the "Notes"). The proceeds of the Notes were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and amount the Escrow Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan.

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

Credit Facilities

Utility

On May 26, 2020, the Utility entered into (i) the Utility RCF Commitment Letter, pursuant to which the Utility RCF Commitment Parties agreed, subject to the terms and satisfaction or waiver of the conditions contained therein, to provide a $3.5 billion revolving credit facility (the "Utility Revolving Credit Facility") to the Utility and (ii) the Utility Term Loan Commitment Letter, pursuant to which the Utility Term Loan Commitment Parties agreed, subject to the terms and satisfaction or waiver of the conditions contained therein, to provide an up to $3 billion term loan credit facility (the "Utility Term Loan Credit Facility," as amended on June 19, 2020) to the Utility. The Utility Revolving Credit Facility has tenor of three years, subject to two one-year extension options. The proceeds from the Utility Revolving Credit Facility were used in part to fund transactions contemplated under the Plan and are intended to finance working capital needs, capital expenditures and other general corporate purposes of the Utility and its subsidiaries. The Utility Term Loan Credit Facility is comprised of two tranches, with tenors of 364 days and 18 months. The proceeds from the Utility Term Loan Credit Facility were used to fund transactions contemplated under the Plan. On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the "Utility Revolving Credit Agreement") with JPM, and Citibank, N.A. as co-administrative agents and Citibank, N.A., as the designated agent as contemplated by the Utility RCF Commitment Letter. The Utility Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of the Utility. In addition, on July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the "Utility Term Loan Credit Agreement") with JPM, as administrative agent, the other lenders from time to time party thereto as contemplated by the Utility Term Loan Commitment Letter. The facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the "Utility 364-Day Term Loan Facility") and a $1.5 billion 18-month term loan facility (the "Utility 18-Month Term Loan Facility"). The maturity date for the 364-Day Term Loan Facility is 364 days after the Effective Date of the Utility Term Loan Credit Agreement and the maturity date for the 18-Month Term Loan Facility is eighteen months after the Effective Date of the Utility Term Loan Credit Agreement.

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

PG&E Corporation

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

The Corporation Revolving Credit Facility matures in three years, subject to two one-year extension options. The proceeds from the Corporation Revolving Credit Facility will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries. On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the "Corporation Revolving Credit Agreement") with JPM, as administrative agent and collateral agent, and the lenders from time to time party thereto as contemplated by the Corporation RCF Commitment Letter. The Corporation Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of PG&E Corporation. 95 -------------------------------------------------------------------------------- On the Effective Date, PG&E Corporation repaid and terminated (i) $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent and (ii) $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.

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

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation's and the Utility's common stock, beginning the fourth quarter of 2017, as well as the Utility's preferred stock, beginning the three-month period ending January 31, 2018. On April 3, 2019, the court overseeing the Utility's probation issued an order imposing new conditions of probation, including foregoing issuing "any dividends until [the Utility] is in compliance with all applicable vegetation management requirements" under applicable law and the Utility's Wildfire Mitigation Plan. On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation "will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date" of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020. In addition, the Corporation Revolving Credit Agreement will require that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of at most 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter. Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. Certain debt instruments contain covenants that restrict the ability of the Utility to pay dividends to PG&E Corporation. PG&E Corporation and the Utility do not expect to commence payment of dividends on its common or preferred stock upon emergence from Chapter 11.

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

Utility Cash Flows

The Utility's cash flows were as follows:

Six Months Ended June 30, (in millions) 2020 2019 Net cash provided by operating activities $ 2,800 $ 2,776 Net cash used in investing activities (3,441) (2,434) Net cash provided by financing activities 9,334 1,399

Net change in cash, cash equivalents and restricted cash $ 8,693

$ 1,741 Operating Activities The Utility's cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the six months ended June 30, 2020, net cash provided by operating activities increased by $24 million compared to the same period in 2019. This increase was primarily due to a $19 million decrease in interest paid during the six months ended June 30, 2020, as compared to the same period in 2019. 96 --------------------------------------------------------------------------------

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

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

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see "Enforcement and Litigation Matters" in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part II, Item 1. Legal Proceedings for more information); •the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility's service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility's customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions and the ability of the Utility to recover any losses incurred in connection with COVID-19 through cost recovery, as well as the impact of COVID-19 on the availability or cost of financing;

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

•the timing and amount of substantially increasing costs in connection with the 2019 and 2020 Wildfire Mitigation Plans that are not currently being recovered in rates (see "Regulatory Matters" below for more information);

•the timing and amount of premium payments related to wildfire insurance (see "Wildfire Insurance" in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information); and

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2018 and 2019 CEMA filings, and other ratemaking and regulatory proceedings.

The Utility had material obligations outstanding as of the Petition Date, including claims related to the 2018 Camp fire and 2017 Northern California wildfires. Future operating cash flows will be materially impacted by the timing of certain transactions and the satisfaction of claims against and interests in the Utility, in accordance with the terms of the Plan.

Investing Activities

Net cash used in investing activities increased by $1,007 million during the six months ended June 30, 2020 as compared to the same period in 2019. The Utility's investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility's nuclear generation facilities. Cash paid by the Utility for capital expenditures was approximately $6.3 billion in 2019. Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur approximately $7.5 billion in capital expenditures in 2020 and between $7.6 billion and $8.2 billion in 2021.

Financing Activities

Net cash provided by financing activities increased by $7.9 billion during the six months ended June 30, 2020 as compared to the same period in 2019. This increase was primarily due to the Utility's ability to obtain $8.925 billion in first mortgage bonds as a result of the confirmation of the Plan. Additionally, the Utility reduced its net borrowings under the DIP facilities by $1.0 billion during the six months ended June 30, 2020, as compared to the same period in 2019.

Cash provided by or used in financing activities is driven by the Utility's financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments.

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ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2019 Form 10-K and "Part II. Other Information, Item 1. Legal Proceedings."

U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service. The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility's expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis. Upon the court's request, on March 2, 2020, the Utility provided to the court its target number of contract tree trimmers for 2020, information regarding the Utility's 2019 inspections of Tower 009/081 on the Cresta-Rio Oso 230 kV Transmission Line (the "Cresta-Rio Oso Line"), information regarding the relationship between priority codes set forth in the Utility's Electric Transmission Preventive Maintenance Manual and the safety factors specified in General Order 95 promulgated by the CPUC, as well as the application of each to the C-hooks of interest on the Cresta-Rio Oso Line. In addition, on April 2, 2020, the Utility submitted a report to the court regarding the Utility's March 19, 2020 collection of equipment from the Cresta-Rio Oso Line. On April 10, 2020, the TCC in the Utility's Chapter 11 Cases and estimation proceedings filed a declaration from a TCC expert concerning Cresta-Rio Oso 230kV Transmission Line evidence collection and removal on March 19, 2020.

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

•employ, on its own payroll, "a sufficient number of inspectors to manage the outsourced tree-trimming work," including pre-inspectors to "identify trees and limbs in violation of California clearance laws that require trimming" and post-inspectors to "spot-check the work of the contracted tree-trimmers to ensure that no hazard trees or limbs were missed," and submit a detailed plan to carry out this requirement by May 28, 2020; •"keep records identifying the age of every item of equipment on every transmission tower and line," ensuring that "every part [has] a recorded date of installation" and "[i]f the age of a part is unknown, [] conduct research and estimate the year of installation;" •"[i]n consultation with the Monitor, [] design a new inspection system for assessing every item of equipment on all transmission towers," using forms that are "precise enough to track what inspectors actually do, such as whether they touch or tug on equipment," take videos of every inspection, and "submit plans for its new inspection system to the [court] for approval by May 28[, 2020];" and

•"require all contractors performing such inspections to carry insurance sufficient to cover losses suffered by the public should their inspections be deficient and thereby start a wildfire."

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

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

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

On May 14, 2020, the court issued an order staying the April 29th order and ordering certain other procedural actions. On June 24, 2020, after a hearing on the Utility's motion for reconsideration, the Utility filed a joint brief with the Monitor overseeing its probation and the Department of Justice, outlining which actions, if any, the court should take regarding the conditions of the Utility's probation. On July 1, 2020, the court issued a notice inviting comments from "any interested party . . . on whether and the extent to which these joint proposed probation conditions should be accepted." One interested party filed comments on July 16, 2020, stating that the proposed probation conditions submitted by the joint parties were inadequate and should be rejected by the court. The CPUC also filed comments indicating it did not oppose the conditions agreed to by the Utility, the Monitor, and the Department of Justice. On June 17, 2020, the court issued an order requiring the Utility to respond to each statement in the Butte County District Attorney's report filed in the criminal prosecution of the Utility in connection with the 2018 Camp Fire entitled "People's Statement of Factual Basis in Support of the Pleas and Sentencing Statement" that the Utility denies is true and provide the reason for the denial. The Utility filed its response on July 1, 2020.

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

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

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

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

REGULATORY MATTERS The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of the proceedings described below, and other proceedings may materially affect PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the 2019 Form 10-K.

Rate Cases

Application for Wildfire Mitigation and Catastrophic Events Interim Rates

On February 7, 2020, the Utility filed an interim relief application seeking $899 million in interim rates related to certain electric distribution costs recorded in the following memorandum accounts: WMPMA, FRMMA, FHPMA, and CEMA. The costs pertain mainly to the years 2017-2019. The application addresses costs recorded in: (i) the WMPMA and FRMMA to comply with the 2019 WMP and other wildfire mitigation costs not otherwise recoverable through rates, (ii) the FHPMA to comply with various fire safety rulemakings through 2019, and (iii) the CEMA for responding to, and restoring customer service after, certain storms and fires occurring in 2019. The Utility submitted a request on March 23, 2020, to reduce the interim rate relief by $8.4 million to the proposed revenue requirement. This reduction, which reduces the requested rate relief to $891 million, relates to the capital cost reduction required by Assembly Bill 1054.

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

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

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

On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or sought to be authorized in rates in the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA. The Utility has proposed a schedule for the proceeding that requests a final decision by the end of 2020 and costs to be recovered in 2021.

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

Application for a Waiver of the Capital Structure Condition

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

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

A Proposed Decision was issued on April 1, 2020. The CPUC approved the PD on May 7, 2020. The PD granted the Utility a temporary waiver of the capital structure requirement until such time as the CPUC finds it appropriate in the Chapter 11 Proceedings OII. As disclosed in Other Regulatory Proceedings, the CPUC's decision in the Chapter 11 Proceedings OII grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility's exit from Chapter 11.

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

2020 Cost of Capital Proceeding

On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility's return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020, as compared to 12% requested by the Utility. The Utility's annual cost of capital adjustment mechanism also remains unchanged. The cost of capital adjustment mechanism can trigger changes in the Utility's authorized ROE and cost of debt, if the 12-month average Moody's Baa bond rate for the period ending September 30, 2020 were to be 100 basis points higher or lower than 4.5 percent (the benchmark). The adjustment to i) ROE would be one-half the basis point change in the bond rate from the benchmark, and ii) authorized cost of debt would be updated. The decision maintains the common equity component of the Utility's capital structure at 52%, as requested by the Utility, and reduces its preferred stock component from 1% to 0.5%, also as requested by the Utility. The decision also approves the cost of debt requested by the Utility. On May 28, 2020, the CPUC issued a decision in the Chapter 11 Proceedings OII that directed the Utility to submit an Advice Letter to update its authorized cost of debt within 30 days of the Effective Date of the Plan. On July 22, 2020, the Utility submitted an Advice Letter requesting to update the authorized cost of long-term debt from 5.16%, as currently authorized, to 4.17% to implement the interest cost savings resulting from the Utility's exit financing. If approved, the Utility's authorized cost of long-term debt will be in effect beginning July 1, 2020.

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

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2017 General Rate Case

As previously disclosed, on September 13, 2019 the Utility submitted an advice letter containing a revised computation of its revenue requirement due to the effects of the Tax Act, which indicated a $282 million net reduction to the 2018 revenue requirement and a $291 million net reduction to the 2019 revenue requirement. The revised gas revenue requirements increased by $21 million and $11 million for years 2018 and 2019, respectively, and the revised electric revenue requirements decreased by $304 million and $302 million for years 2018 and 2019, respectively. On October 17, 2019, the CPUC approved the Utility's advice letter. The Utility incorporated the gas revenue requirement increases into rates through its Annual Gas True-up advice letter beginning on January 1, 2020 and amortized over 12 months. The Utility incorporated the electric revenue requirement reductions into rates through its Annual Electric True-up advice letter beginning on May 1, 2020. The revenue requirement reduction of $175 million related to electric generation is amortized over 12 months and the 2018 revenue requirement reduction of $215 million related to electric distribution is amortized over 10 months. The Utility will incorporate the remaining 2019 revenue requirement reduction of $216 million related to electric distribution with other anticipated changes, such as the change in revenue requirement resulting from the 2020 GRC phase one decision. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility's calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

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

2020 General Rate Case

As previously disclosed, on December 20, 2019, the Utility together with the Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA), TURN, CUE, the CPUC's Office of the Safety Advocate, the National Diversity Coalition, the Center for Accessible Technology, the Small Business Utility Advocates, and California City County Street Light Association filed a motion with the CPUC seeking approval of a settlement agreement that resolves all of the issues raised by these parties in the Utility's 2020 GRC. As a result of the settlement agreement and based on other facts and circumstances known to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility expect to remain on track to satisfy the rate base conditions included in their exit financing documents. In accordance with a January 16, 2020 CPUC decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan the decision, the Utility is required to file with the CPUC on June 30, 2021 a single "general rate case" application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

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

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

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

2015 Gas Transmission and Storage Rate Case

As previously disclosed, in its final decisions in the Utility's 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount forecast to be recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not result in any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery of costs not otherwise disallowed through a separate application upon completion of the audit. As previously disclosed, as a result of the Tax Act, on October 17, 2019, the CPUC approved the Utility's advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the 2018 revenue requirement. The Utility incorporated the revenue requirement reduction into rates through its Annual Gas True-up advice letter beginning January 1, 2020 and amortized over twelve months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility's calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued. 101 --------------------------------------------------------------------------------

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

2019 Gas Transmission and Storage Rate Case

As previously disclosed, on September 12, 2019, the CPUC voted out the final decision in the 2019 GT&S rate case of the Utility. By approving the decision, the CPUC adopted a 2019 revenue requirement of $1.332 billion compared to the Utility's (revised) request of $1.485 billion. This corresponds to an increase of $31 million over the Utility's 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The CPUC also adopted revenue requirements of $1.432 billion for 2020, $1.516 billion for 2021, and $1.580 billion for 2022, compared to the Utility's request of $1.595 billion for 2020, $1.693 billion for 2021, and $1.679 billion for 2022. As previously disclosed, on January 16, 2020, the CPUC approved a final decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, as a result of which the Utility will be required to combine the GRC and GT&S rate cases starting with the 2023 GRC. In accordance with the decision, on June 30, 2021, the Utility is required to file with the CPUC a single "general rate case" application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

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

Transmission Owner Rate Cases

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

As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of 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 FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to FERC for further proceedings consistent with the Court of Appeals' opinion. On July 18, 2019, FERC issued its order on remand reaffirming its prior grant of the Utility's request for the 50-basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order. On March 17, 2020, FERC issued its order denying the requests for rehearing. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of FERC's orders in the Ninth Circuit Court of Appeals. Briefing on the appeal will be completed in October 2020. The Utility is unable to predict the timing and outcome of this proceeding.

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

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

As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility sought a return on equity of 10.9%, which included an incentive component of 50 basis points for the Utility's continuing participation in the CAISO. In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects. Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility's request of 10.90%, and an estimated composite depreciation rate of 2.96% compared to the Utility's request of 3.25%. The ALJ also rejected the Utility's method of allocating common plant between CPUC and FERC jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility's rate base and revenue requirement. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ's initial decision. Once the FERC issues its decision, the Utility expects one or more parties to seek rehearing of that decision and then appeal it to the courts. The Utility is unable to predict the timing and outcome of this proceeding.

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

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

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 was $6.9 billion. The Utility sought a ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility's continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion. Also, as previously disclosed, on September 21, 2018, the Utility filed an all-party settlement with the FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. Additionally, if the Court of Appeals were to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility's continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. See Transmission Owner Rate Cases for 2015 and 2016 above for a discussion of the incentive adder. On December 20, 2018, the FERC issued an order approving the all-party settlement.

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

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

As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case at FERC requesting approval of a formula rate for the costs associated with the Utility's electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility's October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the Effective Date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. The formula rate replaces the "stated rate" methodology that the Utility used in its previous TO rate case filings. The formula rate methodology still includes an authorized revenue requirement and rate base for a given year, but it also provides for an annual update of the following year's revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements will be updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate will be either collected from or refunded to customers. The parties conducted several settlement conferences throughout 2019. On March 31, 2020, the Utility filed a partial settlement with FERC that resolves issues regarding the inputs, and methods used in the formula rate consistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to review transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in TO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base with the CAISO register data base; and requires the Utility to seek FERC authorization before recovering claims related to 2017 and 2018 fires. The remaining, unresolved issues, including regarding the Utility's return on equity, capital structure, depreciation rates, as well as certain questions regarding the Utility's formula rate, have been set for hearing at FERC. The parties recently submitted and the Chief ALJ granted a request that the hearing schedule be held in abeyance until October 1, 2020 pending further settlement discussions. The Utility is unable to predict the timing and outcome of this proceeding. On May 9, 2019, the Utility filed a request with the FERC to modify the formula rate determination of the Utility's capital structure to address certain non-cash charges related to wildfire liability. The filing was accepted by FERC, subject to hearing and refund, on July 8, 2019 and was consolidated with the TO20 rate case. In addition, on June 30, 2020, the Utility filed another request with the FERC to modify the formula rate determination of the Utility's capital structure to address certain financing issuances related to the Utility's emergence from Chapter 11 and requirements of AB 1054. FERC has not yet acted on this second filing.

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

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Nuclear Decommissioning Cost Triennial Proceeding

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses. Detailed studies of the cost to decommission the Utility's nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. As previously disclosed, on December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion to decommission the Diablo Canyon facilities. Also, as previously disclosed, on January 10, 2020, the settlement agreement that the parties had reached in this proceeding was filed with the CPUC, along with a joint motion for adoption of settlement agreement.

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

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

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

Catastrophic Event Memorandum Account Applications

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. The Utility's CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1. 2019 CEMA Application On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with thirteen catastrophic events that included twelve wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire. A prehearing conference was held on November 4, 2019 and a scoping memo was issued on December 6, 2019. On March 10, 2020, the Utility filed a Motion for Interim Rate Relief, requesting $135.4 million of interim rates to be recovered starting August 2020. On April 7, 2020, the ALJ granted the Utility's request to withdraw the motion without prejudice. The Utility may refile it should the 2019 CEMA schedule be delayed. On June 30, 2020, the Utility reported that it reached a settlement in principle with TURN and the PAO, and asked the ALJ to suspend the scheduled evidentiary hearings and give the parties time to finalize a settlement. The ALJ has suspended evidentiary hearings and set a status conference for July 30, 2020. A final decision is expected by the end of 2020.

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

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. 104 -------------------------------------------------------------------------------- On April 25, 2019, the CPUC approved the Utility's request for interim rate relief, allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017), compared to $588 million requested by the Utility. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a Revised Application, Revised Testimony and Revised Workpapers, reflecting a new revenue requirement request of $669 million, pursuant to CPUC ruling allowing these changes.

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

On March 9, 2020, the CPUC issued a modified scoping memo and ruling, requiring the Utility to file by June 30, 2020 a revised application that would include actual 2019 tree mortality costs and an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.

On May 4, 2020, the Utility filed a revised application, which included 2019 tree mortality costs, reflecting a new revenue requirement request of $757 million.

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

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

Fire Hazard Prevention Memorandum Account

The CPUC allows utilities to track and record costs associated with implementing regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. The Utility tracked such costs in the FHPMA through the end of 2019. On December 17, 2019, the Utility, the SED of the CPUC, the CPUC's Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire. Pursuant to the settlement agreement, the Utility agrees, among other things, to not seek recovery of $36 million of wildfire-related expenses recorded in the FHPMA. For more information on the settlement agreement, see Note 11 of the Notes to the Condensed Consolidated Financial Statements. Other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire, the Utility believes such costs are recoverable but rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC.

The amount reflected in this memorandum account as of June 30, 2020 was $261 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

Fire Risk Mitigation Memorandum Account

On March 12, 2019, the CPUC approved the Utility's FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized by SB 901 and AB 1054 to capture mitigation costs of activities not included in a CPUC approved Wildfire Mitigation Plan. The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Mitigation Plan to record costs of wildfire mitigation activities that were beyond the initial identified scope of work. On December 17, 2019, the Utility, the SED of the CPUC, the CPUC's Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agrees, among other things, not to seek recovery of $236 million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For more information on the settlement agreement, see Note 11 of the Notes to the Condensed Consolidated Financial Statements. 105 -------------------------------------------------------------------------------- Other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility intends to seek recovery of the FRMMA balance in a future application, which rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP recorded in the FRMMA.

The amount reflected in this memorandum account as of June 30, 2020 was $98 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

Wildfire Mitigation Plan Memorandum Account

As previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The purpose of the WMPMA is to track costs incurred to implement the Utility's Wildfire Mitigation Plan, as required by Public Utilities Code Sections 8386 et seq, as modified by SB 901 and subsequent bills including AB 1054, AB 111, SB 70, SB 167, SB 247, and SB 560. The WMPMA is required to be established upon approval of a utility's wildfire mitigation plan to track costs incurred to implement the plan. The CPUC approved the memorandum account on August 5, 2019, so the Utility has recorded costs incurred in implementing the Wildfire Mitigation Plan, which was approved May 30, 2020, as of the Effective Date, June 5, 2019. Also, as previously disclosed, other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility anticipates that the recovery of the costs recorded to the WMPMA would occur through a general rate case or future application at which time the CPUC would review the costs for reasonableness as required by AB 1054. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan recorded in the WMPMA, which the Utility expects will be substantial.

The amount reflected in this memorandum account as of June 30, 2020 was $993 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

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

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

•waive deposit requirements for residential customers seeking to reestablish service for one year and expedite move in and move out service requests;

•stop estimated usage for billing attributed to the time period when a home/unit was unoccupied as a result of the emergency;

•identify the premises of affected customers whose utility service has been disrupted or degraded, and discontinue billing these premises without assessing a disconnection charge;

•prorate any monthly access charge or minimum charges;

•implement payment plan options for residential customers;

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

•support low-income residential customers by:

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

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

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

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

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

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

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

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

•meeting and conferring with the Community Choice Aggregators as early as possible to discuss their roles and responsibilities for each emergency customer protection.

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

Covid-19 Pandemic Protections Memorandum Account

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

On June 2, 2020, the Utility submitted an updated advice letter to modify and clarify prior proposals based on CPUC guidance.

The CPUC has not yet approved the Utility's advice letter, therefore, as of June 30, 2020, $35 million in CPPMA costs for the period between March 4, 2020 and June 30, 2020 were recorded in noncurrent Regulatory assets on the Condensed Consolidated Balance Sheets. Other Regulatory Proceedings 107

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Application for Post-Emergence Securitization Transaction

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date. Specifically, the application requests administration of the Stress Test Methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are Stress Test Costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also contemplates a customer credit designed to insulate customers from the charge on customer bills associated with the bonds. The Utility proposes to fund the customer credit through a trust that consists of shareholder assets including: (1) an initial contribution of $1.8 billion; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; and (3) investment returns on the assets in the trust. The Utility anticipates that this will be sufficient to ensure that the customer credits equal the bond charges over the life of the bonds. The Utility also proposes to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. Protests and response to the application were due June 4, 2020 and the Utility filed a reply on June 12, 2020. A prehearing conference was held on June 18, 2020. The Assigned Commissioner issued the scoping memorandum on July 28, 2020 and directed the Utility to file updated testimony, if any, based on its post-emergence financial status by August 7, 2020. The Utility expects that its updated testimony will reflect, among other things, PG&E Corporation's and Utility's exit financings from Chapter 11 and related equity issuances, including to the Fire Victim Trust, in connection with consummating the Plan on July 1, 2020, issuance of revised credit ratings, updated financial forecasts for the Utility and their impacts on the securitization application, including on the Stress Test Costs and the Customer Credit Trust, as well as certain expected tax impacts. The foregoing description of anticipated post-emergence securitization transaction includes "forward-looking statements" within the meaning of Section 27A of the Securities Act, including statements about the expected sources and uses of funding, expected financing transactions (including the potential securitization) and projected balances of assets and liabilities (including cash on hand, accrued interest, trade payables and other amounts). This description reflects PG&E Corporation's and the Utility's expectations as of the date of this filing and remains subject to change. (See "Forward-Looking Statements" above). 2019 Wildfire Mitigation Plan As previously disclosed, on October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. This OIR provided guidance on the form and content of the initial wildfire mitigation plans, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of wildfire mitigation plans to be filed in future years. In this proceeding the CPUC determined, among other things, how to interpret and apply SB 901's list of required plan elements, as well as what additional elements beyond those required in SB 901 should be included in the wildfire mitigation plans. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation's electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to wildfire mitigation plans, which SB 901 requires to be addressed in separate rate recovery applications. On February 6, 2019, the Utility filed its wildfire mitigation plan (the "2019 Wildfire Mitigation Plan") with the CPUC, and amended it subsequently on February 12, February 14, and April 25, 2019. On May 30, 2020, the CPUC approved the 2019 Wildfire Mitigation Plan.

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

2020-2022 Wildfire Mitigation Plan

As previously disclosed, on February 7, 2020, the Utility publicly posted its 2020 Wildfire Mitigation Plan and utility survey. The Utility's 2020 Wildfire Mitigation Plan describes the Utility's wildfire safety programs, which are focused on three key areas: reducing the potential for fires to be started by electrical equipment, reducing the potential for fires to spread, and minimizing the frequency, scope and duration of Public Safety Power Shut-off events, as well as providing historical data requested by the guidelines. 108 -------------------------------------------------------------------------------- On March 18, 2020, the CPUC issued a decision in this proceeding, clarifying that the CPUC's newly created Wildfire Safety Division will review 2020 wildfire mitigation plans, present resolutions for CPUC consideration on the 2020 Plans, and oversee independent evaluation and other compliance activity with regard to both 2019 and 2020 Plans. On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved PG&E's 2020-2022 WMP. The resolutions indicate that while the Utility's 2020-2022 WMP met the minimum requirements for its submission, the deficiencies found, classified as Conditions A, B, or C, will require significant oversight to ensure they appropriately prioritize and remedy the deficiencies. The Utility received 41 Conditions in total with the first set classified as Conditions A, which were completed on July 27, 2020. The second set, Conditions B are due on September 9, 2020 and the third, Conditions C are due as part of the 2021 WMP update in February 2021. The Utility is working to provide all updates and information to meet the Conditions. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan, and the 2020-2022 Wildfire Mitigation Plan recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

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

OIR Regarding Microgrids

As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC sought to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by Spring or Summer 2020, if not sooner. At the CPUC's direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility's proposal contained three components for which it is sought scope and cost recovery authorization of up to approximately $379 million in both expense and capital. On April 1, 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it was seeking to approximately $257 million. The Utility described in its supplemental testimony that it was focusing in 2020 on the use of temporary, mobile generation solutions to power microgrids in 2020 and that the Utility had suspended its solicitation for permanent generation located at substations with online dates in 2020. The Utility's supplemental testimony also attached contracts the Utility had executed with mobile generation vendors for use in 2020. Participants in the solicitation for the permanent generation have been notified of the solicitation's termination. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying on procedural grounds the Utility's motion to supplement its proposal. The CPUC adopted a decision in the first track of the proceeding on June 11, 2020, which approved with conditions each of the Utility's three proposed components and requires the Utility to track costs in a new memorandum account. The decision requires the Utility to seek recovery of the recorded costs for the temporary, mobile generation and associated substation facility equipment in a future track of the proceeding following reasonableness review. The decision requires the Utility to seek recovery of the costs of the community microgrid enablement program through reasonableness review in a future separate application or a general rate case. Failure to obtain a substantial or full recovery of costs could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows.

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

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

OIR Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901

As previously disclosed, on July 8, 2019, the CPUC issued a decision in the CHT proceeding, which adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or 5% of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b). 109 -------------------------------------------------------------------------------- Pursuant to SB 901 and the CPUC's methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate-neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date.

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

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

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

On May 28, 2020, the CPUC approved a final decision in this proceeding. The decision approved PG&E Corporation's and the Utility's Plan with certain conditions and modifications related to certain topics, including but not limited to, governance, operational structure, safety performance, executive competition, and financial condition. Among other things, the decision:

•Board of Directors: provides for certain corporate governance changes, including:

•a requirement to use independent search firms and the director skills matrix to select Board member candidates for at least seven years following emergence from Chapter 11; and

•a requirement to classify the Boards of Directors into two classes, with directors serving two-year terms (an arrangement that would phase out over time, such that all directors elected in 2024 would be elected to one-year terms).

•Safety and Operational Metrics: does not adopt or approve specific safety and operational metrics for the Utility, but directs that such metrics would be developed in a future CPUC proceeding;

•Penalties: directs the Utility to ensure that its Plan of Reorganization provides that "neither confirmation nor consummation of the plan shall affect any pending or future Commission proceeding or investigation, including any adjudication or disposition thereof, and any liability of PG&E Corporation and the Utility, as applicable, arising therefrom shall not be discharged, waived, or released," which could relate to a potential CPUC investigation or proceeding regarding the 2019 Kincade fire, as further specified in the Bankruptcy Court's confirmation order;

•Regional Restructuring: orders the Utility to file by June 30, 2020 an application for approval of a regional restructuring plan;

•Enhanced Enforcement Process: adopts an Enhanced Oversight and Enforcement Process for the Utility;

•Financial Issues: authorizes the Utility to issue debt consistent with the Plan and to update its authorized cost of debt, finding that recovery of the Utility's estimated $154 million in financing-related costs is consistent with AB 1054's "neutral, on average, to ratepayers" requirement, subject to the condition that the Utility demonstrate they are "neutral, on average" when it requests rate recovery;

•Capital Structure: grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility's exit from Chapter 11;

•Earnings Adjustment Mechanism: does not adopt an earnings adjustment mechanism;

•Executive Compensation: imposes certain requirements regarding executive compensation, including:

•a presumption that a material portion of incentive compensation for Utility executives shall be withheld if the Utility's equipment is the ignition source of a catastrophic wildfire; and •a requirement to maintain policies that include provisions that allow for restrictions, limitations, and cancellations of severance payments in the event of certain felony criminal convictions on the part of the Utility, for Utility executives serving at the time of the conduct leading to the conviction. 110 -------------------------------------------------------------------------------- •Structural Proposals: declines to adopt a moratorium on considering proposals for potential changes to the Utility's corporate structure and authorizations to operate as a utility, however, the decision states that:

•separating the Utility "into gas and electric utilities or selling the gas assets … is less of a priority today;"

•the Enhanced Oversight and Enforcement Process supersedes prior proposals to establish periodic review of the Utility's certificate of public convenience and necessity; and

•the existing holding company structure is left in place.

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

Regionalization Application

On June 30, 2020, the Utility filed its application for approval of its Regionalization Proposal with the CPUC. The Utility's proposal would divide its service area into five new regions to further improve safety and reliability, core operations, and be more responsive to the needs of its customers. The Utility's Regionalization Proposal describes the development of these regions, plans to hire new regional leadership, and a new regional organization structure that moves certain work to local regions for both scheduling and execution. The Utility's application requests the CPUC to approve a memorandum account ("Regional Plan Memorandum Account") to record any incremental costs the Utility incurs in connection with the development and implementation of regionalization.

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

Enhanced Enforcement Process

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

Wildfire Fund Non-Bypassable Charge

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of a non-bypassable charge to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the non-bypassable charge is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the investor-owned utilities as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision proposes revenue requirements for the Utility of $404.6 million, which is based on average annual collections and shall expire at the end of the year 2035. On November 25, 2019, an individual intervenor filed an application for rehearing of the decision arguing that the decision constitutes a constitutional violation of procedural due process and an unjust and unreasonable rate increase. On March 2, 2020, the CPUC issued a decision denying the application for rehearing.

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

111 --------------------------------------------------------------------------------

Transportation Electrification

SB 350 (the Clean Energy and Pollution Reduction Act), requires the CPUC, in consultation with the CARB and the California Energy Resources Conservation and Development Commission, to direct electrical corporations to file applications for programs and investments to accelerate widespread transportation electrification. In September 2016, the CPUC directed the Utility and the other large IOUs to file transportation electrification applications that include both short-term projects (of up to $20 million in total) and two-to-five year programs with a requested revenue requirement determined by the Utility. As previously disclosed, on May 31, 2018, the CPUC issued a final decision approving the Utility's two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets. On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters. This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs' transportation electrification investments, and vehicle-grid integration. A prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the assigned commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding. On February 3, 2020 the CPUC issued a draft Transportation Electrification Framework for review and comment. The CPUC has held workshops during the first half of 2020, which will continue throughout the second half of 2020. Approval of the framework is expected by the end of 2020.

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

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

On January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the greenhouse gas reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding will examine whether recent industry related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including but not limited to, gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders. The Utility filed opening comments on the preliminary scope on February 26, 2020 and reply comments on March 12, 2020. The assigned ALJ and assigned commissioner held a prehearing conference on March 24, 2020. The Utility filed a post-prehearing conference Statement on April 1, 2020. On April 23, 2020, the assigned commissioner issued a ruling setting the final scope, schedule and categorization for phase 1 (Tracks 1A and 1B). On July 7, the CPUC held a workshop to address natural gas reliability standards (Track 1A) and on July 21, 2020 a second workshop was held to address market structure and regulations (Track 1B). In accordance with the procedural schedule for Phase I, the CPUC staff is expected to issue its Report in September 2020. Parties may then submit opening and reply comments on the Report.

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

OIR to Consider Strategies and Guidance for Climate Change Adaptation

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

On October 24, 2019, the CPUC adopted a final decision on a portion of phase one (Topic 1 and 2), defining climate change adaptation for California's energy utilities as "adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations." In addition, this decision provides guidance on what data should be used by the investor-owned utilities to perform all climate impact, climate risk, and climate vulnerability analyses undertaken with respect to their infrastructure assets, operations, and customer impacts. Finally, this decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers. 112 -------------------------------------------------------------------------------- On October 22, 2019, The CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed utilities to research and develop a new form of risk assessment, a CVA. CVAs instruct utilities to "examine the risks posed by climate change to their core lines of business, including generation, transmission, distribution, and storage, irrespective of who owns the assets." In addition, the staff proposal provides guidance regarding the data sources used in the CVA, outreach and coordination with the community, and incorporation of CVA findings into RAMP and GRC filings. The Utility provided opening and reply comments on February 18 and March 3, 2020, respectively. On July 6th, 2020, the CPUC issued a proposed decision on Topic 4 and Topic 5 for disadvantaged communities and Climate Vulnerability Assessments ("CVA"). In the proposed decision, the CPUC instructed IOUs to create "climate change teams" across departments, with cross-departmental responsibilities who will report directly to an executive at the SVP level or above. Continuing, the IOUs shall report on organizational structure and provide individual names and department titles. Board members should take responsibility for climate adaptation planning, as informed by senior leadership. The scope of CVAs are proposed to consider climate risks to assets, operations, and services over which IOUs have direct control, as well as third party power providers, and consider promoting equity in Disadvantaged Vulnerable Communities. CVAs are proposed to coincide with each IOUs GRC cycle, and a new chapter on Climate Adaptation is required in future GRCs. A significant program of community outreach and engagement on climate adaptation must also be undertaken by the IOUs, subject to a Community Engagement Plan that they must submit within 90 days of the CPUC's Final Decision in this , and a new chapter on Climate Adaptation is required in future GRCs. A significant program of community outreach and engagement on climate adaptation must also be undertaken by the IOUs, subject to a Community Engagement Plan that they must submit within 90 days of the CPUC's Final Decision in this OIR. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account - CAVAMA, is proposed to cover CVA costs. Opening comments were filed on July 27th.

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

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California. On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8. On January 30, 2020, the CPUC proposed new guidelines. Parties submitted opening and reply comments on the guidelines on February 19, 2020 and February 26, 2020, respectively. As discussed above, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The Utility and other entities (including other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. On May 28, 2020 the CPUC adopted PSPS Phase 2 Guidelines, which requires utilities to restore energy within 24 hours after the end of a PSPS event where possible; to consult with critical facilities on back-up power for PSPS events; and to support access and functional needs populations during PSPS events, including powering medical equipment at customer resource centers. The CPUC's May 28, 2020 decision did not act on the Joint Motion. On June 15, 2020, fourteen parties (including telecommunications providers, CCAs, and 10 cities and counties) filed a joint motion requesting that the CPUC perform a reasonableness review of past IOU PSPS events to determine whether each was reasonable. PG&E Corporation and the Utility are unable to predict the timing and the outcome of this request.

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

Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions issued an order to show cause directing the Utility to show cause why it should not be sanctioned for violations of law or CPUC decisions related to the PSPS events of October 9-12, 2019 and October 23-November 1, 2019. 113 -------------------------------------------------------------------------------- The Utility filed its testimony with the CPUC on February 5, 2020. Parties filed testimony on February 28, 2020; concurrent rebuttal was filed on April 7, 2020. On April 16, 2020, proceedings in the order to show cause phase of this proceeding were suspended indefinitely pending the COVID-19-related restrictions. On July 7, 2020, in response to an email ruling from the ALJ, parties in the order to show cause submitted a joint response that discussed, among other things, the need for evidentiary hearings in the proceeding and a proposed schedule for the remainder of the proceedings. On July 9, 2020, the ALJ held a status conference at which parties discussed those issues. The ALJ indicated that a further ruling, setting forth a schedule for the remainder of the proceeding, would be forthcoming.

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

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

OII to Examine the Late 2019 Public Safety Power Shutoff Events

On November 13, 2019, the CPUC issued an OII to determine "whether California's investor-owned utilities prioritized safety and complied with the Commission's regulations and requirements with respect to their Public Safety Power Shutoff (PSPS) events in late 2019." The first phase of this proceeding will assess for each utility, among other things, (1) the effectiveness of the utility's procedures to notify the public of the PSPS events, (2) the utility's communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utility's management of its resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary. On June 8, 2020, the SED issued a Public Report on the Late 2019 Public Safety Power Shutoff Events. The Report indicated that it described the manner and extent to which each electric investor-owned utility implemented the CPUC's PSPS Guidelines during their late 2019 PSPS events. The Report stated that it was intended to be advisory in nature, subject to modification, and not intended to serve as an adjudicatory-staff investigatory pre-enforcement report. On June 19, 2020, parties to the OII submitted prehearing statements that provided, among other things, views on the appropriate next steps in the proceeding. On June 22, 2020, the ALJ held a prehearing conference that discussed appropriate next steps in the proceeding. The ALJ indicated that a ruling on those issues would be forthcoming.

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

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

Power Charge Indifference Adjustment OIR

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

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

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

On March 26, 2020, the CPUC approved a final decision on departing load forecasting and PCIA bill presentation issues, establishing that the IOUs shall show a PCIA line item in their tariffs and bill summary tables on all customer bills, which shall be implemented by the last business day of 2021. On June 30, 2020, the CPUC issued a PD that would provide a non-Utility provider an option to prepay their entire PCIA obligation. The earliest date the CPUC will consider this prepayment option is August 6, 2020. The proceeding is now examining structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the Utility's portfolios. A PD is expected in the third quarter of 2020. 114 --------------------------------------------------------------------------------

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

Central Procurement of the Resource Adequacy Program

On June 17, 2020, the CPUC issued a decision on the Central Procurement of the RA Program. The decision adopted implementation details for the central procurement of multi-year local RA procurement, ordered the Utility and another IOU to serve as the central procurement entities for their respective distribution service areas, and adopted a hybrid central procurement framework for the multi-year local RA program beginning for the 2023 RA compliance year. The decision requires the Utility, as the central procurement entity for its distribution service area, to conduct a competitive, all-source solicitation for local RA procurement, with any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, or any load serving entity or third-party with an existing local RA contract eligible to bid into the solicitation. The Cost Allocation Mechanism methodology is adopted as the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function. The administrative costs incurred in serving the central procurement entity function shall also be recoverable under the Cost Allocation Mechanism.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 350

On June 30, 2020, the California Governor signed into law SB 350 (the Golden State Energy Act), a bill which authorizes the creation by the Governor of a new entity "Golden State Energy," a nonprofit public benefit corporation, for the purpose of acquiring the Utility's assets and serving electric and gas in the Utility's service territory only in the event that the CPUC determines that the Utility's Certificate of Public Convenience and Necessity should be revoked pursuant to any process or procedures adopted by the CPUC in its decision approving PG&E Corporation's and the Utility's Plan of Reorganization.

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the CHT. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as "securitization"), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

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

Assembly Bill 1054

On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company's equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054. AB 1054 also provides that the first $5.0 billion expended in the aggregate by California's three investor-owned electric utility companies on fire risk mitigation capital expenditures included in their respective approved wildfire mitigation plans will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the investor-owned electric utility companies in accordance with their Wildfire Fund allocation metrics (described above). AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. Each of California's large investor owned utilities have elected to participate in the Wildfire Fund. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund, subject to the conditions set forth in AB 1054. On July 1, 2020, having satisfied the conditions for the Utility's participation in the Wildfire Fund, the Utility deposited approximately $5 billion in the Wildfire Fund, which represents PG&E's initial and first annual contributions. 115 --------------------------------------------------------------------------------

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

ENVIRONMENTAL MATTERS

The Utility's operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of the Utility's activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as "Item 1A. Risk Factors" and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.) CONTRACTUAL COMMITMENTS PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility's generation activities. (See "Purchase Commitments" in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation's and the Utility's contractual commitments, see "Liquidity and Financial Resources" above and MD&A "Contractual Commitments" in Item 7 of the 2019 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K (the Utility's commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for risk mitigation purposes and not for speculative purposes. The Utility's risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. These activities are discussed in detail in the 2019 Form 10-K. There were no significant developments to the Utility's and PG&E Corporation's risk management activities during the six months ended June 30, 2020.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for LSTC, regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, and pension and other post-retirement benefit plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting policies and their key characteristics are discussed in detail in the 2019 Form 10-K. 116 --------------------------------------------------------------------------------

Contributions to the Wildfire Fund

On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. PG&E Corporation and the Utility will account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. At June 30, 2020, PG&E Corporation and the Utility satisfied the eligibility and other requirements set forth in AB 1054 and as a result, upon payment of the initial contribution on the Effective Date, the Wildfire Fund is available to pay for eligible claims arising as of the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising as of the effective date of AB 1054 and the Utility's emergence from Chapter 11, additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. Therefore, PG&E Corporation and the Utility have recorded a current liability of $5.2 billion in "Wildfire fund liability" and $1.5 billion in Other noncurrent liabilities for the present value of unpaid contribution amounts, as well as $6.5 billion in assets for its commitment to make contributions, reduced by amortization, of which $6.0 billion are non-current, called "Wildfire fund asset" in the Condensed Consolidated Balance Sheets. On June 30, 2020, the Utility recorded amortization expense of $173 million related to the coverage received from the effective date of AB 1054 to June 30, 2020. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in "Wildfire fund expense" in the Condensed Consolidated Statements of Income. Contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset. AB 1054 did not specify a period of coverage, therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility used a Monte Carlo simulation based on twelve years of historical data from wildfires caused by electrical equipment to estimate expected loss. The assumptions create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The most significant assumption is the number and severity of catastrophic fires that could occur in California within the participating electric utilities' service territories during the term of the Wildfire Fund. PG&E Corporation and the Utility utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies. Other assumptions include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. PG&E Corporation and the Utility will evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility's service territory. At June 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

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

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