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

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors in this Form 10-Q and the 2021 Form 10-K and a detailed discussion of these matters contained in Item 2. MD&A in the 2021 Form 10-K and this Form 10-Q. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors , including regarding dividends, at http://investor.pgecorp.com, under the “Chapter 11,” “Wildfire and Safety Updates” andUpdates,” “News & Events: Events & Presentations”Presentations,” and “Shareholders: Dividend Information” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident. The information included in an electric incident report is limited and may not include important information about the facts and circumstances about the incident due to the limited scope of the reporting requirements and timing of the report and is necessarily limited to information to which the Utility has access at the time of the report. Ignitions are also reportable under CPUC Decision 14-02-015 when they involve self-propagating fire of material other than electrical or communication facilities; the fire traveled greater than one linear meter from the ignition point; and the Utility has knowledge that the fire occurred. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in Item 1. It should also be read in conjunction with the 2021 Form 10-K.

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

For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors in this Form 10-Q and the 2021 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 “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.

PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $21.1 billion and California net operating loss carryforward of approximately $18.9 billion as of December 31, 2021.

Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility and ShareCo. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC.

PG&E Corporation’s net loss primarily consists of income taxes, interest expense on long-term debt, and charges related to Wildfire-Related Securities Claims. For more information on Wildfire-Related Securities Claims, see Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and sixnine months ended JuneSeptember 30, 2022 and 2021.  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. 

The following discussion presents the Utility’s operating results for the three and sixnine months ended JuneSeptember 30, 2022 and 2021, focusing on revenues and expenses that impacted earnings for these periods. 

The Utility’s electric and natural gas operating revenues that impacted earnings decreasedincreased by $151$83 million, or 4%2%, in the three months ended JuneSeptember 30, 2022, compared to the same period in 2021, primarily due to decreasesthe recognition of approximately $30$180 million in revenues related to the final decision approving $356.3 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system (see “2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate. The increases were partially offset by approximately $80 million of previously deferred revenues recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below), as well as decreases in other miscellaneous revenues..

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $409$520 million, or 6%5%, in the sixnine months ended JuneSeptember 30, 2022, compared to the same period in 2021, primarily due to the recognition of approximately $310 million in revenues related to the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below), the recognition of approximately $180 million in revenues related to the final decision approving $356.3 million in revenue requirements for capital expenditures incurred in the period from 2011 through 2014 for its GT&S system (see “2015 Gas Transmission and Storage Rate Case and 2011-2014 Gas Transmission and Storage Capital Expenditures Audit” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below), increased base revenues authorized in the 2020 GRC, and additional revenues as authorized through the FERC formula rate. These increases were partially offset by a decrease of approximately $80 million of previously deferred revenues recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below).

The Utility’s operating and maintenance expenses that impacted earnings decreased by $389$479 million, or 21%, in the three months ended JuneSeptember 30, 2022, compared to the same period in 2021, as a result of operating cost efficiencies and decreases in the recognition of previously deferred costs including approximately $90 million related to residential uncollectibles and $30$80 million recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below). in the three months ended September 30, 2021 with no comparable charge in the same period in 2022. In addition, in the three months ended September 30, 2021, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2022.

The Utility’s operating and maintenance expenses that impacted earnings decreased by $38$489 million, or 1%8%, in the sixnine months ended JuneSeptember 30, 2022, compared to the same period in 2021, as a result of operating cost efficiencies and decreases in the recognition of previously deferred costs including $110 million related to vegetation management, $90 million related to residential uncollectibles and $30$105 million recognized in conjunction with interim rate relief associated with the WMCE application (see “2020 WMCE Application” below). In addition, during the nine months ended September 30, 2021, the Utility recorded a $124 million charge related to the September 21, 2021 joint motion for approval of settlement agreement associated with the 2020 WMCE filing, with no comparable charge in the same period in 2022. These decreases were partially offset by the recognition of approximately $310 million of previously deferred expenses which were authorized by the settlement agreement for the 2018 CEMA application (see “2018 CEMA Application” below), $85 million in expenses related to the Kincade SED Settlement, and $55 million in expenses related to the Kincade Stipulation and the Dixie Stipulation (each as defined in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1) in the sixnine months ended JuneSeptember 30, 2022, compared to the same period in 2021.

SB 901 securitization charges, net, that impacted earnings increased by $40 million, or 100%, in the three and sixnine months ended JuneSeptember 30, 2022, compared to the same periodsperiod in 2021. In the second quarter of 2022, as a result of the establishment of the SB 901 securitization regulatory asset and liability, the Utility recorded a $40 million charge. For more information, see Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Costs related to wildfires that impacted earnings increaseddecreased by $150$85 million, or 90% in the three months ended JuneSeptember 30, 2022, compared to the same period in 2021. The Utility recognized pre-tax charges of $100 million related to the 2022 Mosquito fire in the three months ended September 30, 2022, as compared to pre-tax charges of $1.15 billion related to the 2021 Dixie fire in the three months ended September 30, 2021. The 2022 Mosquito fire charges were partially offset by $90 million of probable recoveries through insurance and the WEMA in the three months ended September 30, 2022, as compared to $1.06 billion of probable recoveries through insurance, the WEMA, and the Wildfire Fund related to the 2021 Dixie fire in the three months ended September 30, 2021. See “Loss Recoveries” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 below.

Costs related to wildfires that impacted earnings decreased by $108 million, or 41%, in the nine months ended September 30, 2022, compared to the same period in 2021. The Utility recognized pre-tax charges of $150 million related to the 2019 Kincade fire and $100 million related to the 2022 Mosquito fire in the threenine months ended JuneSeptember 30, 2022, as compared to pre-tax charges of $75 million$1.15 billion related to the 2020 Zogg2021 Dixie fire, offset by $80 million of probable insurance recoveries in the three months ended June 30, 2021.

There was no material change toThe Utility’s Wildfire Fund expense that impacted earnings fordecreased by $44 million, or 27%, and $46 million, or 12%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods presented.in 2021, primarily due to accelerated amortization of the Wildfire Fund asset recorded in 2021 as a result of the Wildfire Fund receivable accrued in relation to the 2021 Dixie fire, with no comparable amounts recorded in 2022.

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $90$201 million, or 11%25%, and $174$375 million, or 10%15%, in the three and sixnine months ended JuneSeptember 30, 2022, respectively, compared to the same periods in 2021, primarily due to capital additions and an increase in decommissioning expense beginning in January 2022 as a result of the final 2018 Nuclear Decommissioning Cost Triennial ProceedingNDCTP decision.

There was no material change to interestInterest income that impacted earnings forincreased by $42 million, or 100%, and increased by $54 million, or 318%, in the three and nine months ended September 30, 2022, respectively, compared to the same periods presented.in 2021, primarily due to higher interest rates earned on regulatory balancing accounts.

Interest expense that impacted earnings increased by $11$116 million, or 3%34%, and increased by $27$143 million, or 4%14%, in the three and sixnine months ended JuneSeptember 30, 2022, respectively, compared to the same periods in 2021, primarily due to the issuance of additional long-term debt and an increase in interest rates on variable ratevariable-rate debt.

There was no material change to reorganization items, net that impacted earnings for the periods presented.

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

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

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

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

PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. The collateral posting provisions for some of the Utility’s power and natural gas commodity, and transportation and service agreements state that if the Utility’s credit ratings were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some or all of its net liability positions. The Utility’s credit ratings fell below investment grade in January 2019, at which time the Utility was required to post additional collateral under its commodity purchase agreements.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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 the COVID-19 pandemic. The outbreak of the COVID-19 pandemic, the emergence of variant strains of the virus (including Delta and Omicron), and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have impacted and will continue to impact the Utility for an indeterminate period of time. In particular, the Utility continues to experience increased arrearages. 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 continued suspensioncap on the number of service disconnections for residential customers, and the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” and an observed reduction in non-residential electrical load.Protections.” The Utility has resumed non-residential service disconnections and anticipates resuming residential service disconnections in the fourth quarteras of October 13, 2022. The CPUC has set an annual cap on the number of residential disconnections. The Utility’s accounts receivable balances over 30 days outstanding as of JuneSeptember 30, 2022, were approximately $983 million,$1.1 billion, or $752$869 million higher as compared to the balance as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic.

As of JuneSeptember 30, 2022, PG&E Corporation and the Utility had access to approximately $2.7$2.6 billion of total liquidity comprised of approximately $122$107 million of Utility cash, $117$155 million of PG&E Corporation cash and $2.5$2.3 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities. The 2022 cost of capital application was filed off-cycle based on the extraordinary event of the COVID-19 pandemic and related government response. See “Cost of Capital Proceedings” below for more information.

The Utility established the CPPMA memorandum accounts for tracking costs related to the CPUC’s emergency authorization and order for the period the CPPMA was in effect. As of JuneSeptember 30, 2022, the CPPMA totaled $33$32 million and is reflected in Long-term regulatory assets on the Condensed Consolidated Balance Sheets. In addition to the $33$32 million recorded to the CPPMA, the Utility recorded approximately $95$109 million of undercollections from residential customers from March 4, 2020 to JuneSeptember 30, 2022 to the RUBA, which has been approved by the CPUC and is reflected in Regulatory balancing accounts receivable on the Condensed Consolidated Balance Sheets.

On June 30, 2022, the Governor of California signed AB 205, which included authorization for additional incremental CAPP funding of $958 million for California IOUs to be determined by the California Department of Community Services and Development. The amountUtility and the community choice aggregators in its territory expect to be allocatedreceive $219 million to reduce the Utility’s customers is uncertain.amounts owed by customer accounts in arrears.

The COVID-19 pandemic may continue to impact PG&E Corporation and the Utility financially, and PG&E Corporation and the Utility will continue to monitor the overall impact of the COVID-19 pandemic.

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. 

On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in an amount equal to $1.0 billion, and for general corporate purposes.

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

As previously disclosed, on August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full.

On May 10, 2022, PG&E Wildfire Recovery Funding LLC, a bankruptcy remote, limited liability company wholly owned by the Utility, issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). The Series 2022-A Recovery Bonds were issued in five tranches:

The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

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

The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement as defined below, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024.

As of JuneSeptember 30, 2022, PG&E Corporation and the Utility had $500 million and $2.0$1.8 billion available under their respective $500 million and $4.0 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit (which was $1.0 billion as of June 30, 2022) and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the amendment. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time.

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

On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). The 364-Day 2022A Tranche Loans have a maturity date of April 3, 2023 and bear interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022A Tranche Loans on April 4, 2022. On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding.

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

On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. As of July 21,On August 12, 2022, the SPV has not maderequested such requestan increase to the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, extend the scheduled termination date to September 30, 2024 and implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment.

On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the facility limit.aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility).

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 February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022 and declared a dividend on the Utility’s preferred stock totaling $3.5 million, which was paid on May 15, 2022, to holders of record on April 29, 2022. On JuneSeptember 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on AugustNovember 15, 2022, to holders of record on July 29,October 31, 2022.

On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. No dividend is payable until declared by the Board of Directors of the Utility.

Subject to the dividend restrictions as described in Note 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K, any decision to declare and pay dividends on PG&E Corporation’s common stock in the future will be made at the discretion of the BoardsBoard of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions, and other factors that the BoardsBoard of Directors may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items. It is indeterminate as to when PG&E Corporation currently is unable to predict when it will commence the payment of dividends on its common stock.

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 sixnine months ended JuneSeptember 30, 2022, net cash provided by operating activities increased by $368$720 million compared to the same period in 2021.  This increase was primarily due to a reduction in accounts receivable in 2022 resulting from the CAPP relief payment of approximately $300 million received in January 2022 to reduce the amounts owed by customer accounts in arrears. In addition, during the sixnine months ended JuneSeptember 30, 2022, the Utility made a payment to the Fire Victim Trust of $592 million as compared to a payment of $758 million in the same period in 2021.

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

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K.

Net cash used in investing activities increased by $1.3$3.4 billion during the sixnine months ended JuneSeptember 30, 2022 as compared to the same period in 2021. This increase was primarily driven by a $919 million$1.9 billion increase in capital expenditures, including additional system hardening and emergency response work performed in 2022. Additionally, the Utility purchased $485 million$1.0 billion of investments as part of the creation of the customer credit trust, with no similar purchases in 2021.

The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.  The Utility estimates that it will incur between $7.8 billion and $8.9$9.4 billion of capital expenditures in 2022 and between $7.9 billion and $10.4$11.2 billion in 2023. Cash provided by or used in investing activities is also driven by proceeds and purchases of customer credit trust investments. Additionally, future cash flows used in investing activities will be impacted by the timing and amount related to the intended purchase of the Lakeside Building.

Net cash provided by financing activities increased by $1.1$2.8 billion during the sixnine months ended JuneSeptember 30, 2022 as compared to the same period in 2021. The increase was due to the issuance of $3.6$7.5 billion in SB 901 recovery bonds and a $1.4$1.0 billion increase in net borrowings under credit facilities, partially offset by a $3.3$4.9 billion decrease in proceeds from issuance of long-term debt, net of repayments, during the sixnine months ended JuneSeptember 30, 2022, as compared to the same period in 2021. Additionally, the Utility received an equity contributioncontributions from PG&E Corporation of $212$427 million, which waswere offset by a common stock dividend paymentpayments of $425$850 million. The net increase was also offset by $350$370 million of proceeds received in 2021 from the sale of future revenue from transmission tower license sales, with no similar receipts in 2022.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date or prepayment date of existing debt instruments.  Additionally, future cash flows from financing activities will be affected by the timing and outcome of the Utility’s application for a second AB 1054 securitization transaction. See “Application for Second AB 1054 Securitization Transaction” below for more information. transaction, dividend payments, and equity contributions from PG&E Corporation.

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 2, Note 11, and 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1. that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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

On August 18, 2021, the Presidentthen-president of the CPUC informed the Utility that the CPUC staff intends to conduct a fact-finding review regarding a pattern of self-reported missed inspections and other self-reported safety incidents to determine whether a recommendation to advance the Utility further within the EOEP is warranted.

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

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

As required by the CPUC’s resolution, the Utility submitted a corrective action plan to the CPUC’s Executive Director on May 6, 2021, which is designed to correct or prevent recurrence of the step 1 triggering event, or otherwise mitigate any ongoing safety risk or impact, as soon as practicable, among other things. The corrective action plan addressed the EVM situation that occurred in 2020 and provided a risk-informed EVM work plan for 2021. The Utility is required to update the information contained in the corrective action plan every 90 days, which it has done. The Utility will remain in step 1 of the EOEP until the CPUC determines that the Utility has met the conditions of the corrective action plan. If the Utility does not adequately meet such conditions within the timeframe approved by the CPUC, the CPUC may place the Utility into a higher step of the EOEP, or the Utility may remain in step 1 of the EOEP if it demonstrates sufficient progress towards meeting such conditions.

On October 14, 2022, the CPUC issued a draft resolution authorizing the Utility to exit the EOEP. The UtilityCPUC is unablescheduled to predictvote on the outcome of this regulatory process.draft resolution on November 17, 2022.

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.

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

In recent years, the amount of the costs recorded in these accounts has increased. As of June 30, 2022, the Utility had recorded an aggregate amount of approximately $5.2 billion in costs not otherwise being recovered in existing revenue requirements, if any, for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of September 30, 2022, the Utility had recorded an aggregate amount of approximately $5.7 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA. Of these costs, approximately $800 million was authorized for recovery and accounted for as current, and $4.9 billion was accounted for as long term as of September 30, 2022. See Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to timely recover costs included in these applications.

For more information, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1., “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications,” and “Catastrophic Event Memorandum Account Application” below.

The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the sixnine months ended JuneSeptember 30, 2022 are summarized in the following table:

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation and certain catastrophic events (the “2020 WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”) and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a proposed revenue requirement of approximately $1.28 billion.

On September 21, 2021, the Utility and certain parties filed a motion with the CPUC seeking approval of a settlement agreement that would resolve all of the issues raised by the settling parties in the 2020 WMCE application. The settlement agreement proposes that the Utility recover a revenue requirement of $1.04 billion. The settlement agreement authorizes the Utility to recover a revenue requirement of $591 million over a 24-month amortization period, which is in addition to the interim rate relief of $447 million that was approved by an earlier CPUC decision. On April 7,October 11, 2022, the CPUC extended the statutory deadline forassigned ALJ issued a PD, and the assigned Commissioner issued an APD. The PD would reject the settlement agreement and result in recovery of a revenue requirement of approximately $748 million. The APD would approve the settlement and authorize recovery of a revenue requirement of $1.04 billion, but would modify the settlement agreement to make permanent a 19% reduction in capital expenditures for future cost-recovery periods through the full service life of the subject assets; the settlement agreement had limited this matterperiod to October 1, 2022.three years. The Utility intends to seek further review of both proposed decisions.

For more information regarding this proceeding, see Note 12 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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

The recorded expenditures consist of $1.4 billion in expenses and $197 million in capital expenditures. The costs addressed in the 2021 WMCE application are incremental to those previously authorized in the Utility’s 2017 GRC, 2020 GRC, and other proceedings. The majority of the Utility’s proposed revenue requirement would be collected over a two-year period startingbeginning in January 2023.

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

The CPUC’s schedule indicates a PD will be issued in the fourth quarter of 2022.

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

In addition to the Utility’s responsibilities in responding to catastrophic events, in 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. Through 2019, the costs associated with this work were tracked in the CEMA. In the 2020 GRC decision, the CPUC required the Utility to track these costs in the VMBA for the period beginning January 1, 2020.

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. The Utility filed three revisions to this application, resulting in a total cost recovery request of $763 million.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time. The interim rate relief was implemented, commencing on October 1, 2019.

On March 17, 2022, the CPUC approved a settlement agreement authorizing the Utility to collect a total of $683 million plus interest for the 2018 CEMA application. As noted above, $373 million of the total amount had already been collected in interim rates. The interim rates became final and are no longer subject to refund. The remainder of the authorized revenue requirement will be amortized over a 12-month period, which began on June 1, 2022.

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in proceedings to adjust its regulated return on rate base.

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

Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected depending on the outcomes of these applications.

The Utility’s forward-looking rate cases that are pending, have pending appeals, or were completed during the sixnine months ended JuneSeptember 30, 2022 are summarized in the following table:

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

Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony. On February 25, 2022 and February 28, 2022, the Utility served supplemental testimony (the “Supplemental Testimony”) for its 2023 GRC to reflect the Utility’s integrated wildfire mitigation strategy, including the Utility’s proposals for the initial phase of undergrounding 10,000 miles of electric distribution powerlines in high fire risk areas throughout the Utility’s service area, the EPSS program, and its EVM program. On March 10, 2022, the Utility filed an amended application (the “Amended Application”) that revised and superseded the revenue requirement request in the Original Application. On September 6, 2022, the Utility submitted testimony updating the revenue requirement request in its 2023 GRC proceeding. The Utility is permitted to update its forecast requesttestimony reflected updates for escalation rates and testimony on September 7, 2022 to reflect updated cost escalation factors fromfederal tax law and guidance since the same indices used to developfiling of the Utility’s forecasts.Original Application.

In a GRC,As amended and updated, the CPUC approves annual revenue requirements for the first year (a “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). The Utility’s Amended Application requestedapplication requests revenue requirements of $15.34$16.18 billion and a weighted-average GRC rate base of $50.88 billion for its 2023 test year, an increase of $3.13 billion overyear. The tables below compare the requested revenue requirements and rate base for the GRC period from 2023 through 2026 to those adopted for 2022 in the 2020 GRC and 2019 GT&S revenue requirements for 2022 of $12.21 billion. The Amended Application’s requested revenue requirements for the 2023 test year reduced the Original Application’s request of $15.46 billion. The requested weighted-average GRC rate base for 2023 is approximately $49.18 billion, which corresponds to an increase of $9.97 billion over the authorized rate base for 2022 of $39.2 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized GRC revenue requirements in 2024, 2025, and 2026 by $1.02 billion, $755 million, and $561 million, respectively. The Utility estimated its proposed revenue requirements for 2024, 2025, and 2026 would result in revenue requirement increases of 6.6%, 4.6%, and 3.3%, compared to its total estimated revenue requirements for 2023, 2024, and 2025, respectively. proceedings: