Pg&e Corp,
Fiscal Year 2023.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW This is a combined report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8. See "Ratemaking Mechanisms" in Item 1. Description of the Business regarding how the Utility's revenues are determined. 60

Cash, Cash Equivalents, and Restricted Cash Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. As of December 31, 2023, the Utility had contributed $340 million to its wholly-owned subsidiary and captive insurance company for the administration of wildfire liability self-insurance, of which approximately $8 million was classified as Restricted cash due to minimum capital and surplus requirements (see "Self-Insurance" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). 69

2023 Cost of Capital Increase ROE to 11% and cost of debt to 4.31% Final decision issued December 2022, adopting a 10% ROE. Intervenor application for rehearing denied in August 2023. Intervenor petition for modification filed December 2023.

Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility's non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation. The application, which was filed jointly with Pacific Generation, seeks to establish Pacific Generation as a separate, rate-regulated utility subject to regulation by the CPUC and contemplates the potential sale of a minority interest in Pacific Generation to one or more investors to be identified. The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation. On May 31, 2023, the FERC issued an order approving the transfer of FERC-jurisdictional assets from the Utility to Pacific Generation.

Wildfire-Related Liabilities PG&E Corporation and the Utility are subject to potential liabilities related to wildfires. PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. Potential liabilities related to wildfires depend on various factors, including negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys' fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation or the Utility. For example, the Utility's wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages. The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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 11 of the Notes to the Consolidated Financial Statements in Item 8. The cost of natural gas increased in 2022 as compared to 2021 due to increased customer demand and higher market prices. This was driven primarily by below-normal winter temperatures and prolonged drought conditions, resulting in lower California and Pacific Northwest hydro-electric generation output and higher demand from natural-gas fired generation. Lower natural gas storage levels and regional pipeline constraints also contributed to higher natural gas prices.

Update on Ownership Restrictions in PG&E Corporation's Amended Articles As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn, attributed to PG&E Corporation for income tax purposes. Consequently, any shares of PG&E Corporation common stock owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person's Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility, and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person's effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of outstanding shares. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate.

Nuclear Operations Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, reflect the availability of Diablo Canyon's generation to the California electricity market. Management analyzes capacity factors by comparing Diablo Canyon's actual generation to forecasted annual capacity factors, which reflect planned refueling outages, curtailments for condenser cleaning, allowances for minor curtailments resulting from equipment issues, and curtailments for major ocean storms. Apart from cost-of-service ratemaking and beginning on September 2, 2022, the Utility is entitled to receive a monthly performance-based disbursement. For more information, see "Extension of Diablo Canyon Operations" below. 67 The Utility manages its scheduled refueling outages with the objective of minimizing their duration and maintaining high nuclear generating capacity factors, resulting in a stable generation base for the Utility's wholesale and retail power marketing activities. During scheduled refueling outages, the Utility performs maintenance and equipment upgrades to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. For the years ended December 31, 2022 and 2021, Diablo Canyon achieved an average capacity factor of 90% and 84%, respectively. As previously disclosed, Diablo Canyon Unit 2 experienced five outages between July 2020 and April 2021, each due or related to excessive vibrations within the main generator. In addition to the maintenance and equipment upgrades performed by the Utility during scheduled refueling outages, the Utility has extensive operating and security procedures in place to assure the safe operation of Diablo Canyon. The Utility also has extensive safety systems in place designed to protect the plant, personnel, and surrounding area in the unlikely event of an accident or other incident.

Financial Resources Equity Financings On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement with the Agents, the Forward Sellers and the Forward Purchasers (each as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation's common stock having an aggregate gross sales price of up to $400 million. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into Forward Sale Agreements (as defined in "At the Market Equity Distribution Program" in Note 7 of the Notes to the Consolidated Financial Statements in Item 8) with the Forward Purchasers. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date for this program, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement. PG&E Corporation and the Utility plan to meet their capital requirements for 2023 through internally generated funds and the issuance of long-term debt, short-term debt, and the potential sale of a minority interest in Pacific Generation. (See "Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets" below.) PG&E Corporation does not plan to issue any equity securities in 2023 or 2024. Factors that could affect PG&E Corporation's planned equity issuances include liquidity and cash flow needs, capital expenditures, interest rates, the timing and outcome of ratemaking proceedings, and the timing and terms of other financings, including the potential sale of a minority interest in Pacific Generation.

Future cash flow from operating activities will be affected by various factors, including: •the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries; •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 "Wildfire-Related Securities Class Action" in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and "Regulatory Matters" below for more information); •the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility's service area, the ability of the Utility to collect on its customer receivables, 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 through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing; •the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires; •the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see "Regulatory Matters" below for more information); 73 •the timing and amounts of available funds collected for self-insurance (see "2023 General Rate Case" in the Regulatory Matters section of Item 7. Management's Discussion and Analysis for more information); •the timing of the gain to be returned to customers from the sale of the SFGO and transmission tower wireless licenses and the amounts incurred related to the move to and the leasing of the Lakeside Building; and •the timing and outcomes of the Utility's pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested. 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 16 of the Notes to the Consolidated Financial Statements in Item 8.

Financing Activities Net cash provided by financing activities increased by $2.5 billion during 2022 as compared to the same period in 2021. The increase was primarily due to the issuance of $7.5 billion of SB 901 recovery bonds and a decrease of $850 million in net repayments of short-term debt. These increases were partially offset by a $5.9 billion increase in amounts paid to satisfy long-term debt outstanding in 2022 compared to the same period in 2021. 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, the Utility's future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.

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. During the year ended December 31, 2022 and through the date of this filing, the Utility has continued to make progress on regulatory and legislative matters. •In February 2023, the CPUC approved a final decision, adopting without modification the Utility's settlement agreement in its 2020 WMCE proceeding, pursuant to which the Utility will recover a revenue requirement of $1.04 billion. In January 2023, the Utility submitted a partial settlement regarding the 2021 WMCE application pursuant to which the Utility would receive a revenue requirement of $720.7 million. In December 2022, the Utility filed the 2022 WMCE application requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion.

Utility The table below shows certain items from the Utility's Consolidated Statements of Income for 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. 63 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.

2023 General Rate Case 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 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 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 testimony reflected updates for escalation rates and federal tax law and guidance since the filing of the Original Application. On December 9, 2022, the Utility submitted a post-hearing reply brief. In the reply brief, the Utility updated the revenue requirement request due to the wildfire insurance settlement dated October 7, 2022 discussed below, stipulations with the parties regarding several disputed issues, and a reduction to the Utility's forecast for wildfire system hardening mileage targets over the 2023 to 2026 rate case period. As amended and updated, the Utility's application requests revenue requirements of $15.82 billion and a weighted-average GRC rate base of $50.41 billion for its 2023 test year. 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 proceedings:

OIR to Revisit Net Energy Metering Tariffs On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allow customer-sited renewable generation to grow sustainably among different types of customers. 86 On November 10, 2022, the CPUC withdrew a previously-issued PD and issued a new PD. On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision. For new non-CARE customers interconnecting under the successor tariff, the subsidy is reduced by about 60% for standalone solar and about 45% for solar-paired storage. The decision will also reduce the subsidy for new commercial customers interconnecting under the successor tariff by about 35%. The decision declined to adopt a charge to recover grid and infrastructure costs for new or existing customers and, instead, defers to the ongoing Demand Flexibility OIR, which is considering income-based fixed charges for all customers. The decision does, however, clarify that charges adopted in the Demand Flexibility OIR will apply to NEM and successor tariff customers. The final decision does not reform the legacy period for existing NEM customers.

Electric Asset Inspections The Utility has notified the CPUC of various errors relating to inspections and maintenance of its electric assets or implementation of WMP initiatives. These notices include missed inspections or the inability to locate records evidencing performance of inspections required under CPUC GOs 95 and 165 and errors regarding reporting meeting targets set by the Utility's 2020 WMP. In these notices, the Utility describes the failures and corrective actions the Utility is taking to remediate these issues and to prevent recurrence. Among other corrective measures, the Utility has developed short-term and longer-term systemic corrective actions to address these errors, including performing enhanced inspections for poles with outdated or incomplete GO 165 inspection records and strengthening the Utility's asset registry, as well as corrective actions regarding reporting on the progress toward WMP targets. On October 26, 2022, the Utility notified the CPUC that the Utility's procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum. Among other short- and longer-term corrective measures, the Utility is replacing identified poles on a risk prioritized basis and revising its wood pole replacement procedures in alignment with CPUC requirements. On December 22, 2022 and February 1, 2024, the Utility submitted updates to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165's deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures. The Utility continues to evaluate whether there are additional failures to comply with GO 95 and 165, beyond those identified in submitted self-reports. The Utility intends to update the CPUC upon completion of its reviews and to address any issues it identifies.

Application for Third AB 1054 Securitization Transaction AB 1054 provides that the first $5.0 billion expended in the aggregate by California's three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures has been allocated among the large electric IOUs in accordance with their Wildfire Fund allocation metrics. The Utility's allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On August 10, 2023, the Utility filed an application with the CPUC seeking authorization for a third transaction to use securitization to finance the recovery of up to $1.38 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from August 1, 2019 through the first quarter of 2024, which it subsequently extended through the second quarter of 2024. The $1.38 billion reflected $187 million of recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts approved in the 2023 GRC. These amounts were not included in the first or second securitization transactions. The final amount to be financed using securitization would be based on actual recorded and authorized capital expenditures incurred by the Utility prior to the securitization transaction and not to exceed the remaining $1.38 billion of the Utility's AB 1054 allocation. If approved, the Utility anticipates the transaction will result in the last securitization of AB 1054 capital expenditure amounts subject to the equity rate base exclusion. The application requested that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest, would reduce rates on a present-value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable charge sufficient to pay debt service on the recovery bonds. The application also requested that the CPUC exclude the securitized debt from the Utility's ratemaking capital structure and adjust the Utility's 2020 GRC, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds. The Utility has requested a financing order to be issued within 180 days after the filing of the application on August 10, 2023. On November 22, 2023, the Utility filed opening briefs to update the capital expenditures forecast for the 2023 GRC final decision and extend the forecast capex period through the second quarter of 2024. On February 15, 2024, the CPUC issued a final decision approving the Utility's application. 83

LEGISLATIVE AND REGULATORY INITIATIVES Inflation Reduction Act In 2022, the Inflation Reduction Act became law. The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income ("AFSI") of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage. The U.S. Department of the Treasury and the IRS have broad authority to issue and have issued regulations and guidance to implement its provisions. PG&E Corporation and the Utility continue to evaluate the totality of the law, the regulations issued in connection with it, and its impact on qualifying investments. As of December 31, 2023, the law did not have a material impact on the PG&E Corporation's and the Utility's Consolidated Financial Statements.

Commodity Price Risk The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. 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. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices do not affect earnings. Such fluctuations, however, may impact cash flows. The Utility's natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism. The Utility does not have a balancing account for costs in excess of its revenue requirement for natural gas transportation and storage service to non-core customers. The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders' exposure to these risks. The Utility's value-at-risk was approximately $4 million and $3 million at December 31, 2023 and 2022, respectively. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities.

Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2023 and 2022, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $57 million and $54 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates.

December 31, 2023$926 3 $457 December 31, 2022$814 1 $162 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity. 85

Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. The Utility has liability insurance from various insurers, which provides coverage for third-party claims arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss and they can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Loss recoveries are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, conversations with the Wildfire Fund administrators, the CPUC and FERC, and other information and events pertaining to a particular matter. See "Loss Recoveries" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

Regulatory Accounting As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. The Utility continues to apply ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to "Regulation and Regulated Operations" in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. As of December 31, 2023, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $23.1 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $22.3 billion. 88 Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or court appeals. For some of the Utility's regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility's future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition. A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting 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. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA and RUBA accounts 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. While the Utility generally believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, 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. The Utility must evaluate the likelihood of recovery in future rates each period. In 2022, PG&E Corporation and the Utility recorded a regulatory asset associated with SB 901. As of December 31, 2023, the SB 901 regulatory asset was approximately $5.2 billion. See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility's capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.

Costs Increase in Projected Benefit Obligation at December 31, 2023 Discount rate(0.50)%$2 $1,123 Rate of return on plan assets(0.50)%80 - Rate of increase in compensation0.50 %28 228

Health care cost trend rate0.50 %$6 $39 Discount rate(0.50)%6 86 Rate of return on plan assets(0.50)%11 - 90 NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.

Cost of Electricity The Utility's cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California's cap-and-trade program, and realized gains and losses on price risk management activities. See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. Cost of electricity also includes net energy sales (Utility owned and third parties' generation) in the CAISO electricity markets and directly with third parties. 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.

Tax Matters PG&E Corporation had a U.S. federal net operating loss carryforward of approximately $32.9 billion and a California net operating loss carryforward of approximately $32.6 billion as of December 31, 2023. 62 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," shares of PG&E Corporation common stock held directly by the Utility are attributed to PG&E Corporation for income tax purposes and are therefore effectively excluded from the total number of outstanding equity securities when calculating a person's Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. 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. Furthermore, the activities of the Fire Victim Trust are treated as activities of the Utility for tax purposes. At various dates throughout 2022 and 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2023, the Fire Victim Trust's sale of PG&E Corporation common stock in the aggregate amount of 247,743,590 shares resulted in an aggregate tax benefit of $1.2 billion recorded in PG&E Corporation's and the Utility's Consolidated Financial Statements. Cumulatively through December 31, 2023, the Fire Victim Trust sold all of its 477,743,590 shares resulting in an aggregate tax benefit of approximately $2 billion recorded in PG&E Corporation's and the Utility's Consolidated Financial Statements.

•increased operating cost efficiencies in 2023. SB 901 Securitization Charges, Net The Utility's SB 901 securitization charges, net increased by $659 million, or 108%, in 2023 compared to 2022. These increases were due to the recognition of $1.3 billion in net SB 901 securitization charges, primarily representing the amounts that are refundable to ratepayers as a result of tax benefits realized within income tax expense related to the Fire Victim Trust's sale of PG&E Corporation common stock in 2023, compared to charges of $608 million in 2022. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below. 66

Wildfire-Related Claims, Net of Recoveries Costs related to wildfires decreased by $173 million, or 73%, in 2023 compared to 2022. The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in 2022. These charges were partially offset by $95 million of probable recoveries through insurance and the WEMA related to the 2022 Mosquito fire and $25 million in probable recoveries through the Wildfire Fund related to the 2021 Dixie fire. The Utility recognized pre-tax charges of $425 million related to the 2021 Dixie fire and $100 million related to the 2019 Kincade fire in 2023. These charges were partially offset by $425 million of probable recoveries through the Wildfire Fund, insurance, and the WEMA related to the 2021 Dixie fire. In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $99 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims. See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

(40.1)%(49.2)% Tax credits(2.2)%(1.3)% Fire Victim Trust (3) (80.2)%(64.0)% Other, net 1.1 %2.2 % Effective tax rate(134.8)%(118.2)% (1) Includes the effect of state flow-through ratemaking treatment and the effect of the grantor trust election. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, the Utility's effective tax rate is impacted as these differences arise and reverse. The Utility recognizes 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. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA. (3) Includes the tax effect of the Fire Victim Trust's sale of PG&E Corporation common stock. See "Tax Matters" above and Note 6 of the Notes to the Consolidated Financial Statements in Item 8.

Credit Facilities and Term Loans As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 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 and the facility availability. The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents. 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.

Other investing activities(291) Net decrease in cash used in investing activities$907 Cash used in investing activities - 2023$(9,162) Net cash used in investing activities decreased by $907 million, or 9%, in 2023 compared to 2022. The decrease was primarily due to a $1.3 billion decrease in purchases, net of proceeds, related to customer credit trust investments in 2023. This decrease was partially offset by a $145 million intercompany loan repayment in 2022, with no similar transaction in 2023, and a $130 million increase in capital expenditures, primarily due to new customer connections and responses to winter storm events. 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 and customer credit trust investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust and customer credit 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. Pursuant to SB 901, the funds in the customer credit trust, along with accumulated earnings, are used exclusively to fund a monthly credit to customers. 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 $10.4 billion of capital expenditures in 2024. Additionally, future cash flows used in investing activities could be impacted by the timing and amount of contributions to the self-insurance captive (see "Self-Insurance" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8) and to the customer credit trust, including $1.0 billion to be contributed in 2024 (see Note 5 of the Notes to the Consolidated Financial Statements in Item 8). 73

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 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and in "Regulatory Matters" below 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. 74

Cost Recovery Proceedings Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such requests. For instance, 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 on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA 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, the CPUC may authorize the Utility to recover less than the full amount of its costs. In recent years, the amount of the costs recorded in these accounts has increased. 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 December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA. Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. If the amount of the costs recorded in these accounts continues to increase or the delay between incurring and recovering costs lengthens, PG&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. 75 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8, and "Wildfire Mitigation and Catastrophic Events Cost Recovery Applications" below. The Utility's cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

Forward-Looking Rate Cases 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 "cost of capital" proceedings to adjust its regulated return on rate base. The Utility's future earnings will depend on the revenue requirements authorized in such rate cases. The Utility also expects to file its SB 884 cost application with the CPUC after the OEIS and the CPUC approve guidelines (see "SB 884 10-Year Distribution Undergrounding Program" below). 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 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. The Utility's forward-looking rate cases that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table:

The Utility may be unable to attract and retain specialty personnel and may face workforce disruptions. The Utility's workforce is aging, and many employees are or will become eligible to retire within the next few years. The Utility's efforts to recruit and train new field service personnel may be ineffective, and the Utility may be faced with a shortage of experienced and qualified personnel in certain specialty operational positions. Additionally, the Utility could experience workforce disruptions from personnel in those positions as a result of labor activity, the COVID-19 pandemic or other pandemics, or governmental regulation of pandemic protections. If the Utility were to experience such a shortage or disruptions, work stoppages could occur.

Risks Related to Other Enforcement Matters, Investigations, and Regulatory Proceedings PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process. The EOEP is a six-step process with potentially escalating CPUC oversight and enforcement measures based on specific "triggering events" identified for each of the six steps. If the Utility is placed into the EOEP, it will be subject to additional reporting requirements and additional monitoring and oversight by the CPUC. Higher steps of the process (steps 3 through 6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility's Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility). The process contains provisions for the Utility to cure and exit the process if it can satisfy specific criteria. The EOEP states that the Utility should presumptively move through the steps of the process sequentially, but the CPUC may place the Utility into the appropriate step of the process upon occurrence of a specified triggering event. PG&E Corporation and the Utility could incur significant costs to comply with laws and regulations and be adversely affected by legislative and regulatory developments. The Utility and its operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules. These rules could change, which could change the Utility's compliance obligations and the costs to comply with these rules. Non-compliance with these rules could result in the imposition of material fines on PG&E Corporation and the Utility, other regulatory exposure, significant litigation, and reputational harm, which could materially affect PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows.

Environmental The environmental rules to which the Utility's operations are subject relate to air quality, water quality and usage, remediation of hazardous substances, and the protection and conservation of natural resources and wildlife. Also, SB 100 (the 100 Percent Clean Energy Act of 2018) increased the percentage from 50% to 60% of California's electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from renewable portfolio standard-eligible or carbon-free resources by 2045. Failure to comply with SB 100 could result in fines imposed on PG&E Corporation and the Utility that could be material. The Utility develops its capital plans based on forecasts, including those around load growth, gas system planning, and transportation electrification, which assume that California continues to pursue consistent environmental policies. If the federal government withdraws its support for grid modernization or prohibits California from pursuing its environmental policies, or if California changes its policies, PG&E Corporation and the Utility may be unable to meet their environmental and financial goals.

•enter into any sale-leaseback transactions; and •enter into swap agreements. The restrictions contained in these material financing agreements could affect PG&E Corporation's and the Utility's ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation's and the Utility's ability to finance their operations and expenditures, make strategic acquisitions, investments, or alliances, sell assets, restructure their organization, or finance their capital needs. Additionally, PG&E Corporation's and the Utility's ability to comply with these covenants and restrictions may be affected by events beyond their control, including prevailing regulatory, economic, financial and industry conditions. PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims. On the Emergence Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in "Wildfire-Related Securities Claims-Claims in the Bankruptcy Court Process" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline. 49 Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in "Wildfire-Related Securities Claims-Claims in the Bankruptcy Court Process" in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). Such payment may have a material adverse impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. PG&E Corporation common stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation's ability to use its net operating loss carryforwards and other tax attributes. PG&E Corporation has incurred and may also incur in the future significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the "capital stock") and other interests designated as "stock" of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the "Equity Securities," and such restrictions on transferability and ownership, the "Ownership Restrictions") in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation's ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid. Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities. Additionally, the application of the Ownership Restrictions, as defined in PG&E Corporation's Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility. See "Tax Matters" in Item 7. MD&A for an example of these calculations. Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.

PG&E Corporation may not be able to use some or all of its net operating loss carryforwards and other tax attributes to offset future income. As of December 31, 2023, PG&E Corporation had net operating loss carryforwards for PG&E Corporation's consolidated group for U.S. federal and California income tax purposes of approximately $32.9 billion and $32.6 billion, respectively, and PG&E Corporation incurred and may also continue to incur significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the IRC (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an "ownership change," 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 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). 50 As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the IRC. However, whether PG&E Corporation underwent an ownership change as a result of the transactions in PG&E Corporation's equity that occurred pursuant to the Plan or in combination with other changes in the ownership of PG&E Corporation's equity depends on several factors outside PG&E Corporation's control and the application of certain laws that are uncertain in several respects. Accordingly, the IRS may successfully assert that PG&E Corporation has undergone an ownership change pursuant to the Plan. If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. In particular, limitations imposed on PG&E Corporation's ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. Further, PG&E Corporation's ability to utilize its net operating loss carryforwards is critical to PG&E Corporation's and the Utility's commitment to make certain operating and capital expenditures. Failure to obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock. PG&E Corporation is a holding company and relies on dividends, distributions and other payments, advances, and transfers of funds from the Utility to meet its obligations. PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation's consolidated assets are held by the Utility. Accordingly, PG&E Corporation's cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility. The ability of the Utility to pay dividends or make other advances, distributions, and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends and certain restrictive covenants contained in the agreements of those subsidiaries. Additionally, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and to meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility's ability to pay dividends or other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation's ability to meet its obligations. California law and certain provisions in the Amended Articles and the amended and restated bylaws of PG&E Corporation (the "Amended Bylaws") may prevent efforts by shareholders to change the direction or management of PG&E Corporation. The Amended Articles and the Amended Bylaws contain provisions that may make the acquisition of PG&E Corporation more difficult without the approval of the Board of Directors, including the following: •until 2024, the Board of Directors will be divided into two equal classes, with members of each class elected in different years for different terms;

Inflation and supply chain issues may adversely affect PG&E Corporation and the Utility. PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased and may continue to increase more quickly than expected as a result of inflation. Additionally, the Utility has experienced shortages in certain items, longer lead times, and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work. PG&E Corporation and the Utility may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely affect PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows.

Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to: •The Enhanced Oversight and Enforcement Process; •Legislative and regulatory developments; •Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject;

The electric power and gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy. The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, electric vehicles, energy storage, fuel cells, energy efficiency, and demand response technologies. These developments will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure and state infrastructure modernization (e.g., rail and water projects). The Utility may be unable to effectively adapt to these potential business and regulatory changes, for instance by failing to meet customer demand for new business interconnections in a timely manner. The CPUC is also conducting proceedings to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources and consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. If the Utility is unable to effectively adapt to these potential business and regulatory changes its business model and its ability to execute on its strategy could be materially impacted. Various jurisdictions within California have enacted prohibitions or restrictions on use and consumption of natural gas, for example in buildings, that will reduce the use of natural gas. Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer being "used and useful," potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of "used and useful," the asset is removed from rate base, which results in a reduction in associated rate recovery). However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. Inability by the Utility to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility's financial condition, results of operations, liquidity, and cash flows. These industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility's inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility's financial condition, results of operations, liquidity, and cash flows. The Utility's operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event, or physical attack. The Utility's electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks. Private and public entities, such as the North American Electric Reliability Corporation, and the U.S. federal government, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility's operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility's operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility's ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility's assets or operations or those of third parties. 41 The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility's financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. The Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility's customers. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California's electricity market related to grid modernization and customer choice. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility's systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility's information technology systems could impact the Utility's ability to track or collect revenues and to maintain effective internal controls over financial reporting.

Risks related to financial conditions, including risks related to: •PG&E Corporation's and the Utility's substantial indebtedness; •Restrictions in indebtedness documents; •Appeals of the Confirmation Order; •Potential additional dilution to holders of PG&E Corporation common stock; •Any substantial sale of stock by existing stockholders; •Ownership and transfer restrictions associated with PG&E Corporation common stock; •Tax-related risks and uncertainties, including the grantor trust election for the Fire Victim Trust; •The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; •Restrictions on PG&E Corporation's and the Utility's ability to issue dividends; •PG&E Corporation's reliance on dividends, distributions and other payments from the Utility; •Restrictions on shareholders' ability to change the direction or management of PG&E Corporation; •The COVID-19 pandemic; 36

Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below. 35

Risks Related to Operations and Information Technology The Utility's electricity and natural gas operations are inherently hazardous and involve significant risks. The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. See "Electric Utility Operations" and "Natural Gas Utility Operations" in Item 1 above. The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities. In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives. For more information, see "The operation and decommissioning of the Utility's nuclear generation facilities expose it to potentially significant liabilities, and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire" below. The Utility's ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, some of which are beyond the Utility's control, including those that arise from: •the breakdown, failure of, or supply challenges with equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption, or other catastrophic events; •an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow; 39 •the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; •a significant prolonged electrical black-out that results in damage to the Utility's equipment or losses for customers or other third parties; •the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage; •the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; •the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility's assets are built; •the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion); •inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; •operator or other human error; •a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences; •an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently; •construction performed by third parties that damages the Utility's underground or overhead facilities, including, for example, ground excavations or "dig-ins" that damage the Utility's underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system; •the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility's facilities; leaking or spilled insulating fluid from electrical equipment; and release of contaminants caused by the failure of battery energy storage systems; and •attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war. For more information, see "The Utility's operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack" below. The occurrence of any of these events could interrupt fuel supplies, affect demand for electricity or natural gas, cause unplanned outages or reduce generating output, damage the Utility's assets or operations, damage the assets or operations of third parties on which the Utility relies, damage property owned by customers or others, and cause personal injury or death. As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any such incidents also could lead to significant claims against the Utility. Further, the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, and the Utility may have less control over contractors than its employees. The Utility may retain liability for the quality and completion of the contractor's work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions or inactions. 40

Any such occurrences could materially affect PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. 43

Risks Related to Environmental Factors Severe weather events, extended drought, and climate change could materially affect PG&E Corporation and the Utility. Extreme weather, drought and shifting climate patterns have intensified the challenges associated with many of the other risks facing PG&E Corporation and the Utility, particularly wildfire management in California. The Utility's service area encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as drought conditions and extreme heat followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihood and severity of extraordinary wildfire events. In particular, the risk posed by wildfires, including during the recent wildfire seasons, has increased in the Utility's service area as a result of an ongoing extended period of drought, bark beetle infestations in the California forest, and wildfire fuel increases due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors. Precipitation patterns in California vary significantly from year to year, often leading to periods of severe to extreme drought. Drought conditions often occur and can persist in nearly all of the Utility's service area depending on the amount of precipitation received in the current or previous water years. More than half of the Utility's service area is in an HFTD. Contributing factors other than environmental can include local land use policies and historical forestry management practices. The combined effects of extreme weather and climate change also impact this risk. In January 2018, the CPUC approved a statewide fire-threat map that shows that approximately half of the Utility's service area is facing "elevated" or "extreme" fire danger. Approximately 25,000 circuit miles of the Utility's nearly 80,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs. Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business or operational disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility. Any such event could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Any such event also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility's practices or the failure of electric and other equipment of the Utility. Further, the Utility has been studying the potential effects of climate change (increased severity and frequency of storm events, sea level rise, land subsidence, change in temperature extremes, changes in precipitation patterns and drought, and wildfire) on its assets, operations, and services, and the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant. Consequences of these climate-driven events may vary widely and could include increased stress on the energy supply network due to new patterns of demand, reduced hydroelectric output, physical damage to the Utility's infrastructure, higher operational costs, and an increase in the number and duration of customer outages and safety consequences for both employees and customers. As a result, the Utility's hydroelectric generation could change, and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, climate hazards such as heatwaves, windstorms, and flooding caused by rising sea levels and extreme storms could damage the Utility's facilities, including gas, generation, and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries, or regulators could order the Utility to perform additional work. The Utility anticipates that the increased costs would generally be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. See "Concerns about high rates for the Utility's customers could negatively impact PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows" below. Events or conditions caused by climate change could have a material impact on the Utility's operations and could result in lower revenues or increased expenses, or both. If the CPUC fails to adjust the Utility's rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected. 44

The Utility's operations are subject to extensive environmental laws, and such laws could change. The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is or may be identified as a potentially responsible party under federal and state environmental laws. These costs can be difficult to estimate due to uncertainties about the extent of contamination, emerging contaminants, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties, and the Utility's recorded liabilities for known environmental obligations may not accurately estimate its losses. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Environmental remediation costs could increase in the future as a result of new legislation or regulation, the current trend toward more stringent standards, or stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions. The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future, or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover through rates. Some of the Utility's environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. See "Environmental Regulation" in Item 1 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. The Utility's costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, changes in estimated costs, and the extent to which actual remediation costs differ from recorded liabilities have had, and may continue to have, a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows.

Privacy In June 2018, the State of California enacted the California Consumer Privacy Act of 2018 (the "CCPA"), which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that created the California Privacy Rights Act (the "CPRA"), which amended and expanded the CCPA. The State of California enacted the CPRA in November 2020, with most provisions operative as of January 1, 2023 and applicable to personal information collected beginning January 1, 2022. Final CPRA regulations are in development. Failure to comply with the CCPA and the CPRA could result in litigation, audits, and the imposition of material fines on PG&E Corporation and the Utility. Additionally, PG&E Corporation and the Utility collect and retain certain personal information of their customers, shareholders, and employees in connection with their business. PG&E Corporation's and the Utility's risk management and information security measures may be ineffective, and the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information. If any of these events were to transpire, it could subject PG&E Corporation and the Utility to financial liability. PG&E Corporation and the Utility are subject to federal and state privacy laws, which grant consumers rights and protections, including, among other things, the ability to opt out of receiving certain communications and certain data sharing with third parties.

The Utility is subject to extensive regulations and enforcement proceedings in connection with compliance with such regulations could result in penalties. The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with matters that the CPUC's SED may investigate. The SED can launch investigations at any time on any issue it deems appropriate. In addition, the OEIS has authority to approve and oversee compliance with the WMP and may determine that the Utility has failed to substantially comply with its WMP. 46 The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC GOs or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance. CPUC staff could also impose penalties on the Utility in the future in accordance with its authority under the gas and electric safety citation programs. The amount of such fines, penalties, or customer refunds depends on a variety of factors and 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 also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. See "Risks Related to Wildfires" above. The Utility is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations. If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties, the amount of which could be substantial, and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; for example, by enabling parties to challenge the Utility's request to recover costs that the parties allege are somehow related to the Utility's violations. The Utility's ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility's actual costs could exceed its authorized or forecasted costs due to various factors. The Utility's financial results depend on its ability to earn a reasonable return on capital, including long-term debt and equity, and to recover costs from its customers, through the rates it charges its customers as approved by the CPUC and the FERC. PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility or if the amount of actual costs incurred differs from the forecast or authorized costs embedded in rates. The outcome of the Utility's ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility's regulators, consumer and other stakeholder organizations, and customers, about the Utility's ability to provide safe, reliable, and affordable electric and gas services. If the CPUC does not authorize sufficient funding for investments in the Utility's infrastructure, it may negatively impact the Utility's ability to modernize the grid and make it resilient to risks related to climate change, including wildfires. In addition to the amount of authorized revenues, PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility's actual costs differ from authorized or forecast costs. The Utility's ability to recover its costs and earn a reasonable rate of return can be affected by many factors, including the time delay between when costs are incurred and when those costs are recovered through rates. The CPUC or the FERC may not allow the Utility to recover costs on the basis that such costs were not reasonably or prudently incurred or for other reasons. Further, the Utility may be required to incur expenses before the relevant regulatory agency approves the recovery of such costs. For example, the Utility has incurred, and continues to incur, costs to strengthen its wildfire mitigation and prevention efforts before it is clear whether such costs will be recoverable through rates. Also, the CPUC may deny recovery of uninsured wildfire-related costs incurred by the Utility if the CPUC determines that the Utility was not prudent.

Risks Related to PG&E Corporation's and the Utility's Environment and Financial Condition PG&E Corporation's and the Utility's substantial indebtedness may adversely affect their financial health and operating flexibility. PG&E Corporation and the Utility have a substantial amount of indebtedness, most of which is secured by liens on certain assets of PG&E Corporation and the Utility. As of December 31, 2023, PG&E Corporation had approximately $4.65 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation's $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and $500 million of borrowings under the secured term loan agreement entered into in June 2020), and the Utility had approximately $48.0 billion of outstanding indebtedness. In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $2.0 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million. Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility's assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets or using them for other financing transactions. This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: •limiting their ability or increasing the costs to refinance their indebtedness; •limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; •limiting their ability to use operating cash flow in other areas of their business; •increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and

The Utility may be unable to manage its costs effectively. The Utility has set a goal to increase its capital investments to meet safety and climate goals, while also achieving operating cost savings. The Utility's ability to achieve such savings depends, in part, on whether the Utility can improve the planning and execution of its work by continuing to implement the Lean operating system. Even if the Utility is able to reduce some costs, other emerging priorities, such as emergency response, public purpose programs, wildfire mitigation initiatives, or California's clean energy transition, could require it to reinvest those savings. Concerns about high rates for the Utility's customers could negatively impact PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. The rates paid by the Utility's customers are impacted by the Utility's costs, commodity prices, and broader energy trends. The Utility's capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, leveling demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customers' rates. In particular, the Utility will need to make substantial, sustained investments to its infrastructure to adapt to climate change, enable the clean energy transition, and mitigate wildfire risk. For more information on factors that could cause the Utility's costs to increase, see "The Utility's ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility's actual costs could exceed its authorized or forecasted costs due to various factors" above. The CPUC considers affordability as it adjudicates the Utility's rate cases, and concerns about affordability could cause the CPUC to approve lesser amounts in the Utility's ratemaking or cost recovery proceedings. The Utility generally recovers its electricity and natural gas procurement costs through rates as "pass-through" costs. Increases in the Utility's commodity costs directly impact customer bills. Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM and NBT, which allows self-generating customers to receive bill credits for power exported to the grid, shifts costs to other customers. Under this structure, NEM and NBT customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, including costs associated with funding social equity programs, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. These unpaid costs are subsidized by customers not participating in NEM or NBT. Accordingly, as more electric customers switch to the NBT and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM or non-NBT customers. Other long-term trends could also increase costs for gas customers. Natural gas suppliers are subject to compliance with CARB's cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). Increased renewable portfolio standards in the electric sector could also reduce electric generation gas load. CARB may also require aggressive energy efficiency programs to reduce natural gas end use consumption. Additionally, the Bay Area Air Quality Management District has adopted rules that restrict the sale of gas space and water heating appliances, and the CARB is considering similar rules. If other jurisdictions also adopt similar rules, reduced gas demand could accelerate customers replacing natural gas appliances with electric appliances. The combination of reduced load and increased costs to maintain the gas system could result in higher natural gas customer bills. In addition, some local city governments have passed ordinances restricting use of natural gas in new construction and, if other jurisdictions follow suit, this could affect future demand for the provision of natural gas. If fewer customers receive gas from the Utility, the Utility's gas system maintenance costs, many of which cannot be reduced in the short term even if gas quantities decrease, would be borne by fewer customers. Finally, a mandate to purchase renewable natural gas for core customers could lead to increased costs for core customers if utilities are competing with the transportation sector for supplies of renewable natural gas. 52 A confluence of technology-related cost declines, along with sustained or increased federal or state subsidies, could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility's bundled electric service which could further reduce energy demand. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could increase the energy rates for other customers. If rates were to rise too rapidly, customer usage or the number of customers could decline. A decrease in the volume of sales, among which the Utility's costs are allocated, could further increase rates.

•Recovery of excess costs in connection with wildfires; and •Implementation of wildfire mitigation initiatives. Risks related to operations and information technology, including risks related to: •The hazardous nature of the Utility's electricity and natural gas operations; •Changes in the electric power and natural gas industries; •A cyber incident, cybersecurity breach, or physical attack;

•Severe weather events, extended drought and climate change and events resulting from these conditions (including wildfires); and •Extensive environmental laws.

Additionally, under the doctrine of inverse condemnation, courts have imposed liability against utilities on the grounds that losses borne by the person whose property was damaged through a public-use undertaking should be spread across the community that benefited from such undertaking, even if the utility is unable to recover these costs through rates. In fact, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation. Legal challenges to that denial were unsuccessful. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility's service area. Inverse condemnation imposes strict liability (including liability for attorneys' fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities' electric transmission lines. The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other litigation against PG&E Corporation or the Utility. Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility's equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. The Utility's significant infrastructure investment, vegetation management, and de-energization strategies do not eliminate wildfire risk and may not prevent future wildfires. Once an ignition has occurred, the Utility is unable to control the extent of damages. The extent of damages for a wildfire is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire. In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility's proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or any future wildfires. For more information about the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility may be unable to recover all or a significant portion of its costs in excess of insurance coverage in connection with wildfires, through rates, or from the Wildfire Fund in a timely manner. The Utility could incur substantial costs in excess of insurance coverage or amounts potentially available under the Wildfire Fund under AB 1054 in the future in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire. The Utility may not be allowed to recover costs in excess of insurance or amounts potentially available under the Wildfire Fund under AB 1054 in the future either through FERC TO rates or as costs recorded to the WEMA, even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. The inability to recover all or a significant portion of costs in excess of insurance through rates or by collecting such rates in a timely manner could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. For more information on wildfire recovery risk, see "The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires" above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 38

•The Utility's ability to manage its costs effectively; and •Inflation and supply chain issues. Risks Related to Wildfires The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires. If the Utility does not have an approved WMP, the Utility will not be issued a safety certification and will consequently not benefit from the presumption of prudency or the AB 1054 disallowance cap. Under AB 1054, the Utility is required to maintain a safety certification issued by the OEIS to be eligible for certain benefits, including a cap on Wildfire Fund reimbursement and a reformed prudent manager standard. The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company's actions or inactions that resulted in the applicable wildfire constituted "conscious or willful disregard for the rights and safety of others," or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited. In addition, if the Utility fails to maintain a valid safety certification at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility. The Utility will be required to reimburse amounts that are determined by the CPUC not to be just and reasonable. For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California's other participating electric utility companies. If the Utility is unable to maintain an AB 1054 safety certification or if the Wildfire Fund is exhausted, the inability to access the Wildfire Fund could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the ten-year contribution period for the fund. The timing and amount of any potential charges associated with the Utility's contributions would also depend on various factors. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which the Utility recognizes impairment for the reduction in future coverage due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service area of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund may not ultimately outweigh these substantial costs. PG&E Corporation and the Utility could be liable as a result of the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires. Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur losses in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire. PG&E Corporation's and the Utility's recorded liabilities for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information. The Utility could be subject to significant liability in excess of recoveries that would be expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have been the subject of investigations, regulatory enforcement actions, or criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 37 Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to "make restitution to the victim or victims in an amount established by court order" that is "sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of" the Utility's underlying conduct, in addition to interest and the victim's or victims' attorneys' fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. There have been numerous other wildfires in the Utility's service area, of which the Utility has not been alleged or determined to be a cause. The Utility could be alleged or determined to be a cause of one or more of these wildfires.

The Utility may not effectively implement its wildfire mitigation initiatives. The Utility's infrastructure is aging and poses risks to safety and system reliability. The Utility's wildfire mitigation initiatives may not be successful or effective in preventing or reducing wildfire-related losses. The Utility will face a higher likelihood of catastrophic wildfires in its service area if it cannot effectively implement these efforts and its WMPs. For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs. The CPUC will assess penalties on the Utility if there is a finding that the Utility has failed to substantially comply with its WMPs. Wildfires can occur even when the Utility follows its procedures. For instance, a wildfire may be ignited and spread even in conditions that do not trigger proactive de-energization according to criteria for initiating a PSPS event or where EPSS has been implemented on Utility equipment. The Utility's inspections of vegetation near its assets may not detect structural weaknesses within a tree or other issues. If the Utility's wildfire mitigation initiatives are not effective, a wildfire could be ignited and spread. In addition, on a risk-informed basis, the Utility is making efforts to reduce the frequency and impacts of PSPS. The Utility may be subject to mandated changes to, or restrictions on, its operational practices, regulatory fines and penalties, claims for damages, and reputational harm if the Utility does not execute PSPS in compliance with applicable rules and regulations. The Utility establishes the criteria under which it implements PSPS in its territory. To the extent the Utility's criteria for implementing PSPS are not sufficient to mitigate the risk of wildfires, the Utility does not fully implement PSPS when criteria are met due to other overriding conditions or the Utility's regulators mandate changes to, or restrictions on, its criteria or other operational PSPS practices, the Utility will face a higher likelihood of catastrophic wildfires in its territory during high-risk weather conditions. PG&E Corporation and the Utility cannot predict the timing and outcome of the various proceedings and litigation in connection with its wildfire mitigation initiatives. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings, or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility's implementation of its wildfire mitigation initiatives, which could result in fines, penalties, customer rebates, other payments, or the Utility's failure to obtain cost recovery for amounts expended on these initiatives. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other wildfire mitigation initiatives or liability for damages) could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS and EPSS programs have had an adverse impact on PG&E Corporation's and the Utility's reputation with customers, regulators and policymakers and future PSPS events and EPSS outages may increase these negative perceptions. For more information, see "Regulatory Matters" in Item 7. MD&A.

Other Regulators The CEC is a California agency with responsibility for energy policy and planning. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC establishes forecasts of future energy needs used by the CPUC in determining the adequacy of utilities' and other load-serving entities' electricity procurement. The CEC also promotes energy management and conservation programs, including setting standards for building and appliance energy efficiency and load management programs. The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See "Environmental Regulation - Air Quality and Climate Change" below. The NTSB is an independent U.S. government investigative agency responsible for civil transportation accident investigations, including pipeline accidents. The NTSB also conducts special investigations and safety studies, and issues safety recommendations to prevent future accidents. The California Geologic Energy Management Division is the state agency responsible for establishing and enforcing regulations for the operation of the Utility's underground gas storage facilities. The Department of Transportation's ("DOT") Pipeline and Hazardous Materials Safety Administration has established regulations regarding the design, construction, operation, maintenance, integrity, safety, and security of natural gas distribution, transmission, and underground storage facilities. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities it regulates in California. 18 The OEIS is a state agency responsible for reviewing and approving the Utility's WMP and for evaluating the Utility's implementation of the WMP. The OEIS is also responsible for reviewing and issuing the Utility's annual safety certification, annually reviewing and approving the Utility's executive compensation plan, conducting assessments of the Utility's safety culture, conducting field inspections of wildfire mitigation activities, and reviewing proposed undergrounding plans under SB 884. In addition, the Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. Delay in obtaining, or failure to obtain and maintain, any such permits, authorizations, or licenses could prevent construction of new facilities, limit or prevent continued operation of existing facilities, or result in significant additional costs or restrictions on operations. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy or use public property for the operation of the Utility's business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility's electric or natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties. In most cases, the Utility's franchise agreements are for an indeterminate term, with no expiration date. For more information see Item 1A. Risk Factors.

Cost of Capital Proceedings The CPUC periodically conducts a cost of capital proceeding to authorize the Utility's capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. The rate of return, or cost of capital, is the weighted average cost of debt, preferred equity, and common stock a utility has issued to finance its utility capital investments. The CPUC's cost of capital proceedings generally take place in a consolidated proceeding with California's other large investor-owned electric and gas utilities. For more information about the cost of capital proceedings, see "Regulatory Matters - Cost of Capital Proceedings" in Item 7. MD&A.

•Delivered electricity to customers in 2023 that was 100% GHG free (see "Electricity Resources" below for more information). •Helped customers avoid emissions and manage energy costs through robust energy efficiency programs. •Managed contracts for more than 3.5 GW of battery energy storage to be deployed over the next several years and operated 183 MW of Utility-owned battery storage, strengthening California's grid efficiency and reliability. •Helped enable the total number of electric vehicles operating in the Utility's service area to exceed 550,000; installed more than 475 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and launched a first of its kind vehicle-to-grid program enabling customers to leverage their electric vehicles to power their home. •Brought the total number of interconnected private solar customers to more than 800,000 and supported more than 70,000 customers who have installed battery storage at their homes or businesses. •Continued to advance decarbonization initiatives for the Utility's natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule and accelerated initiatives to meet its voluntary 2030 reduction goal. The Utility also launched an initiative to purchase California-produced renewable natural gas for its natural gas customers, toward a target to procure renewable natural gas to serve 15% of its bundled residential and small commercial demand by 2030. The CPUC coordinates the planning of supply resources through the Integrated Resource Planning ("IRP") proceeding and has determined that replacing the power generated by Diablo Canyon is the responsibility of all LSEs within the CAISO. Looking ahead, the Utility expects its GHG-free energy supply mix of renewable, large hydroelectric, and nuclear generation resources to decrease as, beginning in 2023, the Utility was required to offer, for allocation or sale, renewable sources eligible under California's RPS program that the Utility procured on behalf of customers that subsequently switched to non-Utility providers. These requirements were established to comply with regulatory mandates and to manage customer affordability. Towards the end of the decade and beyond, the Utility's GHG-free energy supply mix is expected to grow relative to 2025 levels as the Utility procures new GHG-free generation and storage to meet California's IRP GHG emissions reduction targets and California's clean energy goals. PG&E Corporation's and the Utility's voluntary goal continues to be to deliver 70% RPS clean electricity by 2030, compared to a state mandate of 60% (see "Air Quality and Climate Change" below for more information).

Energy Storage Energy storage improves system reliability and supports California's decarbonization goals by integrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, under which the Utility was required to procure 580 MW of qualifying storage capacity by the end of 2020, with all energy storage projects required to be operational by the end of 2024. As of December 31, 2023, the Utility was on track to meet its storage goals by the end of 2024. Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023. In January 2022, the Utility also requested CPUC approval for another 1,600 MW of storage to be completed by the summer of 2024, which would bring the Utility's total energy storage system capacity to more than 3,330 MW. Finally, the Utility is soliciting 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, to have these resources online between 2026 and 2028. In order to address both its bundled portfolio need and to help to meet State planning and policy objectives to increase long-duration storage capacity after 2028, the Utility is pursuing regulatory approval to increase the nameplate generating capacity of its Helms Pumped Storage Facility. 30

Electricity Transmission Transmission lines deliver electricity at high voltages and over long distances from power sources to transmission substations closer to customers. A strong transmission system supports reliable and affordable service, ability to meet state energy policy goals, and support for a diverse generation mix, including renewable energy. As of December 31, 2023, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 33 electric transmission substations with a capacity of approximately 66,000 MVA. The Utility's electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

In 2023, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools. 33 Natural Gas Operating Statistics The following table shows the Utility's operating statistics from 2021 through 2023 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2023, 2022 or 2021.

(2) These amounts represent revenues authorized to be billed. Competition Trends in Market Demand and Competitive Conditions in the Electricity Industry The Utility expects customer electric load to increase in coming years primarily as a result of electrification of buildings and transportation. The Utility is not able to predict how quickly this electrification will occur. The Utility expects customer demand for gas to decrease in the coming years, primarily in response to policies supporting California's climate goals. California law allows qualifying non-residential electric customers of IOUs to purchase electricity from energy service providers rather than from the utilities up to certain annual limits specified for each utility. This arrangement is known as DA. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility. The Utility continues to provide transmission, distribution, metering, and billing services to DA customers at the election of their energy service provider. The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of DA and CCA customers while they were the Utility's customers. The Utility remains the electricity provider of last resort for these customers. Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. 34 The Utility is also impacted by an increasing quantity of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, put upward rate pressure on non-NEM customers. The successor to the NEM tariffs, the NBT, will provide bill credits at a lower rate, which reduces the level of upward rate pressure on non-NEM or non-NBT customers, but does not eliminate such upward rate pressure. Like NEM customers, customers interconnecting on the NBT, are required to pay an interconnection fee, utilize time of use rates, and pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for non-NEM or non-NBT customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. See "Concerns about high rates for the Utility's customers could negatively impact PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows" in Item 1A. Risk Factors and "Regulatory Matters - OIR to Revisit Net Energy Metering Tariffs" in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers, in some cases bypassing the Utility's electric infrastructure entirely. Those entities may also rely upon FERC open access tariffs and Utility infrastructure to deliver their energy for resale at retail to existing or potential new Utility customers. These entities may also seek to acquire the Utility's transmission or distribution facilities through eminent domain for use in serving electricity at retail to existing or potential new Utility customers. As a result, the Utility could lose customers (residential, commercial, and industrial) or experience limited growth in the municipality. See "Jurisdictions may attempt to acquire the Utility's assets through eminent domain, and third parties may attempt to acquire the Utility's customers by bypassing the Utility's electric infrastructure system" in Item 1A. Risk Factors. It is also expected that some publicly-owned utilities will build new or duplicate transmission or distribution facilities to serve existing or potential new Utility customers, bypassing the Utility's electric infrastructure. In some instances, microgrid formation is a key factor in a community's choice to engage governmental entities. Some private companies have also called for changes in law that could allow those companies to privately serve electricity to retail customers without being regulated by the CPUC as public utilities. To the extent such changes occur and result in large customers reducing the share of transmission, distribution, and non-bypassable charges they pay, PG&E Corporation's and the Utility's financial condition and results of operations could be materially impacted. The effect of such types of retail competition generally is to reduce the number of utility customers, leading to decreased growth or a reduction in the Utility's rate base. The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service area through a competitive bidding process managed by the CAISO.

PG&E Corporation's and the Utility's operating revenues, income, and total assets can be found below in Item 8. Financial Statements and Supplementary Data. The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation's telephone number is (415) 973-1000 and the Utility's telephone number is (415) 973-7000. This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules, and regulations. 11 Over the past several years, Northern California has experienced major wildfires. For more information about material wildfires, see Item 7. MD&A, and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. This 2022 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these 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 and "Forward-Looking Statements" above.

Emissions Data PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility's third-party verified voluntary GHG inventory reported to The Climate Registry for 2021, which is the most recent data available, totaled Scope 1 and 2 emissions of approximately 4.6 million metric tons of CO2 equivalent (MMT CO2e) and Scope 3 emissions of approximately 42 MMT CO2e, the majority of which came from customer natural gas use. The following table shows the 2021 GHG emissions data the Utility reported to the CARB, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.

0.001 0.001 22 Nuclear Fuel Disposal Nuclear power plant operations produce gaseous, liquid, and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools, and equipment contaminated through use. Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities' customers. The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility's two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay. As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. In September 2012, the DOJ and the Utility executed a settlement agreement that provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs. The claim for the period June 1, 2021 through May 31, 2022, totaled approximately $10.5 million and is under review by the DOE. Amounts reimbursed by DOE are refunded to customers through rates. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

Ratemaking Mechanisms The Utility operates under a "cost-of-service" ratemaking model, which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and to earn a return on invested capital ("cost-of-service ratemaking"). In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers ("revenue requirements"). In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecasted basis. Revenue authorized by the CPUC through GRC proceedings is intended to provide the Utility a reasonable opportunity to recover its costs and earn a return on its investments in generation and distribution assets and general plant (also referred to as "rate base"). The Utility's revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, and financing expenses). The Utility's costs of equity and long-term debt are generally approved in the CPUC's cost of capital proceedings. In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to "pass through" to customers (referred to as "Utility Revenues and Costs that did not Impact Earnings" in Item 7. MD&A), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs. FERC revenue requirements are set through a FERC-approved formula rate. The Utility's rate of return on electric transmission assets is determined in the FERC TO proceedings. Other than certain gas transmission and storage revenues, the Utility's base revenues are "decoupled" from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility's base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility's earnings primarily depend on its ability to manage its base operating and capital costs (referred to as "Utility Revenues and Costs that Impacted Earnings" in Item 7. MD&A) within its authorized base revenue requirements. Due to the seasonal nature of the Utility's business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads. Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating. From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.

All PG&E Corporation and Utility officer compensation currently is funded by shareholders. Safety The Utility's strategy to deliver on safety outcomes focuses on workforce, and public safety. In 2023, in addition to deploying the safety management system, the Utility targets mitigations to the highest risk work. The Utility's safety metrics include the number of SIF-A incidents and the SIF-P rate, which measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2022, the Utility had seven SIF-A incidents, which resulted in three fatalities and four serious injuries, and a SIF-P rate of 0.11. Additionally, the Utility measures DART. In 2022, the Utility's DART was 0.67, which was 34% lower than in 2021 and its lowest rate in the past five years. Throughout the COVID-19 pandemic, PG&E Corporation and the Utility have continued to monitor activities at the Centers for Disease Control and Prevention and the World Health Organization. PG&E Corporation and the Utility have updated their protocols and actions in accordance with guidance from these organizations, following state and local health and safety regulations, and in consultation with the Utility's medical director. PG&E Corporation and the Utility have also remained focused on protecting the health and safety of their employees, contractors and the Utility's customers, while continuing to perform critical utility work, and have continued to monitor and track the impact of the pandemic, modifying or adopting new policies in support of their employees' health and safety as pandemic conditions and governmental response have changed.

Renewable Energy Resources California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. SB 350 increased the amount of renewable energy that must be delivered by most LSEs, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period, to 50% of their total annual retail sales by the end of the 2028-2030 compliance period, and in each three-year compliance period thereafter, unless changed by legislative action. SB 350 provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California's electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as "pass-through" costs. The Utility also may be subject to penalties for failure to meet the higher targets. 29 Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated to comprise 40% of total annual retail sales in 2022.

Biopower5 % Geothermal- % RPS-Eligible Small Hydroelectric2 % Solar24 % Wind9 % Total40 % (1) Estimated renewable procurement amounts are expected to be consistent with Power Content Label reporting and adjustments, based on current CEC guidelines. (2) Estimated renewable procurement percentages above and renewable compliance percentages are expected to be consistent; however, final RPS compliance reporting is subject to a different methodology and may result in some differences between the two percentages.

Under cost-of-service ratemaking, a utility's earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. See "Ratemaking Mechanisms" below and "Regulatory Matters" in Item 7. MD&A for more information on specific CPUC and FERC proceedings. Generally, differences between forecast costs and actual costs (discussed in "Utility Revenues and Costs that Impacted Earnings" in Results of Operations in Item 7. MD&A) can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing their debt. PG&E Corporation and the Utility have set goals to reduce their debt over time, including reducing PG&E Corporation's debt by at least $2 billion by the end of 2026. PG&E Corporation and the Utility expect that reducing the consolidated debt will help them achieve investment grade credit ratings for their unsecured securities, for the benefit of both customers and investors. For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8. Pursuant to SB 901, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to recover $7.5 billion of 2017 wildfire claims costs, which was approved by the CPUC on February 28, 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 Series 2022-A Recovery Bonds on May 10, 2022 and $3.9 billion aggregate principal amount of Series 2022-B Recovery Bonds on July 20, 2022. The net proceeds from both transactions were used to reimburse the Utility for previously incurred recovery costs, including the retirement of $5.0 billion of Utility debt and the repayment of a portion of the loans outstanding under the Utility's revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility intends to use a portion of the remaining proceeds to fund the redemption of $1.0 billion of Utility debt. For more information, see "Application for Post-Emergence Securitization Transaction" in Item 7. MD&A. 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, as well as the Utility's preferred stock. PG&E Corporation's and the Utility's ability to issue dividends is subject to restrictions. 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. On June 15, 2022, the Board of Directors of the Utility also reinstated the dividend on the Utility's common stock. For more information, see "Dividends" in Item 7. MD&A. Total capital expenditures (including accruals) recorded in 2022 were $9.6 billion. The Utility's total capital expenditures (including accruals) are forecasted to be between $7.9 billion and $11.2 billion for 2023, between $7.9 billion and $12.2 billion for 2024, between $8.0 billion and $12.7 billion for 2025, between $8.1 billion and $13.3 billion for 2026, and between $8.1 billion and $13.8 billion for 2027. The completion of projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, community requests or protests, weather, and other unforeseen conditions. 14 The Utility expects to make additional capital expenditures, the recovery of which will be subject to future regulatory approval, including the 2023 GRC. These expenditures include capital expenditures exceeding amounts authorized in the 2020 GRC and 2019 GT&S, and expenditures to be included in a later stage of the 2023 GRC or separate applications. These expenditures are expected to primarily be for wildfire mitigation, transportation electrification, and the Lakeside Building. Additionally, $3.21 billion of fire risk mitigation capital expenditures will be excluded from the Utility's equity rate base pursuant to AB 1054. PG&E Corporation and the Utility are committed to keeping gas and electric services affordable for all customers. The Utility's capital investment plan, increasing procurement of renewable power and energy storage, increasing environmental regulations, and the cumulative impact of other public policy requirements collectively place continuing upward pressure on customer rates. Certain CPUC proceedings could impact different types of customers differently. Similarly, although the Utility generally recovers its electricity and natural gas procurement costs through rates as "pass-through" costs, commodity prices rose substantially in 2022, relative to 2021. The Utility has set a goal to increase customer capital investments while also limiting customer impacts, including by reducing non-fuel Operating and maintenance costs by two percent per year and by seeking efficient financing. The Utility plans to meet its two percent non-fuel Operating and maintenance cost reduction goal through increased efficiency, including waste elimination through the Lean operating system. The Utility has a number of programs in place to assist low-income customers, such as the CARE program. Under the CARE program, income-qualified customers can receive a monthly discount of 20% or more on their gas and electric bill. PG&E Corporation's and the Utility's Corporate Sustainability Report, which is available to the public, describes the companies' progress toward world-class performance measured with the triple bottom line framework.

In 2021, the Utility spent $4.01 billion with certified diverse suppliers, representing 38.7% of its total spend. Performance: Underpinning the Triple Bottom Line PG&E Corporation and the Utility use the Lean operating system, which includes four basic "plays:" visual management; operating reviews; problem solving; and standard work. Visual management allows teams to see how they are performing against their most important metrics using real-time data. PG&E Corporation and the Utility hold daily, weekly, and monthly operating reviews designed to align the performance of workers closest to the work with the goals and objectives of senior leadership. These brief meetings help the Utility identify gaps and quickly develop plans to support the teams performing the work and give the Utility more visibility, control and predictability in its operations. Problem solving involves a structured approach to identifying, containing, analyzing, and solving problems in order to capitalize on opportunities. Standard work reduces costs and increases productivity by ensuring a consistent company-wide method for completing a task. For instance, the Lean operating system helped the Utility identify patterns in the conditions of ignitions and led to the implementation of EPSS and drove significant benefit and understanding in how PG&E Corporation and the Utility manage customer satisfaction. PG&E Corporation's and the Utility's performance is also driven by an increased focus on alignment on shared outcomes among its leadership and within the organization. In 2023, PG&E Corporation's and the Utility's Lean deployment will focus on a fifth play, waste elimination, which enables the companies to identify and eliminate inefficiencies in both process and workflow in a sustainable manner, as well as the continued adoption of a performance playbook and improvements to financial visibility and controls. PG&E Corporation and the Utility have implemented a regional service model to bring the Utility closer to the hometowns it serves. Through the regional service model, the Utility has restructured its service area into five regions, with leaders in each region to deliver improved public and employee safety, customer service, and operational reliability outcomes. PG&E Corporation and the Utility are committed to designing an electric system that is resilient to climate change, decarbonized, and optimized to local and system needs. California has experienced unprecedented weather conditions in recent years and the Utility's service area remains susceptible to additional wildfire activity. In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including: •Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them more rapidly in the event of a disturbance to help prevent potential ignitions. After EPSS was initiated, both the size and number of CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average. 15 •Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions. Since its inception in late 2017, the PSPS program has become more targeted because the Utility has developed more granular risk models, including adding consideration of vegetation management and maintenance tag statuses for scoping PSPS events. The Utility has also installed sectionalizers for more targeted de-energizations of circuits and transmission lines. In 2022, the Utility did not have any PSPS events. •Vegetation management: The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and clear vegetation that might grow or fall into utility equipment. The Utility is also increasing oversight and engagement with the contractors supporting vegetation management work. •Asset inspections: Since 2018, the Utility has reoriented its asset inspections programs toward asset condition and consequence risk, particularly wildfire risk, and these programs have become more thorough, standardized, digitized, and verifiable. The Utility uses risk-informed inspection cycles. In 2022, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections. As a result of the improved inspection program, the Utility's inspections in recent years have begun to more thoroughly identify equipment conditions. •System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTDs and installing stronger and more resilient equipment. As the Utility's asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions than in prior years. Hardening methods include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground. In 2021, the Utility announced a program to underground 10,000 miles of electric distribution lines in high wildfire risk areas. In 2022, the Utility undergrounded 180 miles of lines, which exceeded its plan to underground 175 miles of lines. Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk. The Utility also brought online two additional "remote grids" in 2022, which allow distribution lines in HFTDs to be removed and replaced with locally sited resources. Remote grids can reduce costs and fire risks, while maintaining service to participating customers. As a result of these measures, the Utility significantly reduced both the size and number of CPUC-reportable ignitions and number of acres burned in 2022, compared to prior years.

Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Utility's two nuclear generating units at Diablo Canyon and the Utility's independent spent fuel storage installation at Humboldt Bay. See "Electricity Resources" below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated that the Utility incur substantial costs at Diablo Canyon, and substantial costs could be required in the future. For more information about Diablo Canyon, see Item 1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Material Effects of Compliance with Governmental Regulations As indicated above, the Utility's business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. Compliance with such extensive government regulations requires substantial expenditures and has had in the past and may continue to have in the future a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, cash flows and competitive position. For more information about costs incurred to comply with government regulations and related material effects on PG&E Corporation and the Utility, see Item 1A. Risk Factors, "Liquidity and Financial Resources" and "Regulatory Matters" in Item 7. MD&A, and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8.

Adapting to the Physical Impacts of Climate Change Effectively managing physical climate risk will become increasingly critical as the physical impacts of climate change become increasingly frequent and severe over the coming years in California. The Utility's climate resilience efforts continue to focus on characterizing and mitigating the physical impacts of climate change to the Utility's infrastructure, assets, and operations. The Utility is making substantial investments to build a more resilient system that can better withstand extreme weather and related emergencies. For more information on such investments, see "Performance: Underpinning the Triple Bottom Line" above. The Utility's preparations for the physical risks of climate change include an updated, more detailed, system‑wide CVA of the Utility's assets, operations, and services, which will be completed and filed with the CPUC in mid-2024. The updated CVA will improve the Utility's understanding of its exposure to climate hazards in the near- and long-term and the sensitivity of assets and operations to these hazards. It will also inform the Utility's understanding of the ease or difficulty of various options for adapting to changing conditions. In the past few years, the Utility's electric distribution system has experienced multiple major outage-causing events associated with extreme heat events and peak loads. Peak loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment, increased electricity demand driven by rising air conditioning installation and usage, and continued electrification of transportation and buildings. The Utility's assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine (fluvial), and precipitation related (pluvial) flooding because of climate‑driven changes in precipitation and sea level rise. The risk of damage to or interruptions of operations at facilities such as substations is predicted to increase over time due to sea level rise. Electric and gas equipment and safe access for operations must be prepared for these changing conditions. Changing precipitation dynamics may impact the Utility's hydroelectric generation. Diminishing future water availability and altered runoff timing during extreme drought poses risks to hydropower generation, operations, and revenue. Also, extreme rain events suggest enhanced risk of hydropower asset damage or failure associated with flooding, which in the worst cases (e.g., uncontrolled water release) may have catastrophic impacts. Climate change will also continue to intensify the potential for wildfires throughout California. Models incorporating future temperature and precipitation projections suggest that landscape susceptibility to wildfire within the Utility's service area will continue to increase over time, with an expansion of areas that may become HFTD and an intensification of risk within HFTDs. Climate change may also result in increased potential of lines to cause ignitions or to require PSPS events, as well as the potential for the Utility's equipment to sustain damage from wildfires of any origin. 21 The Utility's updated CVA will be used to inform changes to design and construction standards for equipment and facilities to increase infrastructure resilience to current and future extreme weather conditions. Results from the updated CVA will be incorporated into the Utility's key risk and planning functions, as well as asset management strategy, to identify priority adaptive actions. The Utility has also engaged with CPUC-designated disadvantaged and vulnerable communities throughout the CVA process to better understand customer perspectives regarding energy system resilience. The Utility has conducted regional community engagement campaigns throughout its service area to understand how some of the most vulnerable communities the Utility serves think about climate hazards and adaptation. This information will help the Utility plan adaptive climate action aligned with customer and community perspectives. In addition to updating the CVA, the Utility regularly reviews relevant scientific literature regarding climate change to incorporate appropriate information into its operations. For example, based on a report about potential major atmospheric river events, the Utility updated and modified its flooding emergency response plan. The Utility's commitment to increasing resilience to climate change includes aligning its resources and business strategy with California's clean energy goals, the Utility's climate strategy, and advocating for policies and programs that enable safe and reliable energy for the Utility's customers in light of climate change. For example, the Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected increases in demand for electricity.

20222021 Total NOx emissions (tons)121 139 NOx emissions rate (pounds/MWh)0.01 0.01 Total SO2 emissions (tons) 11 14 SO2 emissions rate (pounds/MWh)

Electricity Transmission Owner Rate Cases The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect through rates in the TO rate case. In its TO rate cases, the Utility uses a formula rate methodology, which includes an authorized revenue requirement and rate base for a given year but also provides for an annual update of the previous year's revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are 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 are either collected from or refunded to customers. These FERC-approved rates are included by the CPUC in the Utility's retail electric rates and by the CAISO in its transmission access charges to wholesale customers. For more information, see "Regulatory Matters - Transmission Owner Rate Cases" in Item 7. MD&A. The Utility also recovers a portion of its revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations. These wholesale customers are charged individualized rates based on the terms of their contracts. 24

Program-Specific Memorandum Account and Balancing Account Costs Periodically, costs arise outside of the CPUC's GRC proceedings or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, new programs, 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 reasonable. For instance, these accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. Recovery of the costs tracked in these memorandum accounts through rates requires CPUC authorization in separate proceedings, the outcome of which the Utility may be unable to predict. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts. The CPUC may authorize recovery of costs tracked in the balancing accounts on either a "one-way" basis, which typically only allows actual costs to be recovered up to a pre-established cap, or a "two-way" basis, which typically allows actual costs to be recovered, and in some cases subject to further CPUC review. For more information, see "Regulatory Matters - Cost Recovery Proceedings" in Item 7. MD&A and Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

Natural Gas Procurement, Storage, and Transportation Costs The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electric rates. The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as "core" customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its CPIM described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with adjustments for under-collections and over-collections made in subsequent monthly rate changes. The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio. Under the CPIM, the Utility's natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered through rates. One-half of the costs above 102% of the benchmark are recoverable through rates, and the Utility's customers receive in their rates 80% of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of these savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. The FERC approves the United States tariffs governing payments by shippers (including the Utility) for pipeline service, and the Canada Energy Regulator, the Canadian regulatory agency, approves the applicable Canadian tariffs. The transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as a cost of electricity. 26

For more information, see "Human Capital" below. Planet The planet element of the triple bottom line represents PG&E Corporation's and the Utility's commitment to protect and serve the environment. This commitment extends beyond compliance with various state and federal environmental, health, and safety laws and regulations. PG&E Corporation and the Utility believe that integrating and managing climate change and other environmental considerations in the companies' business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, coworkers, and other stakeholders. Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility's business and economic opportunity for the communities it serves. The Utility is committed to delivering safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards. To build resilience to these hazards, the Utility is working to systematically integrate forward-looking climate data and tools into its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate change policy in California, and work directly with local governments and communities on adaptation solutions. PG&E Corporation and the Utility are also committed to helping heal the planet. PG&E Corporation's and the Utility's Climate Strategy Report, which is available to the public, describes the companies' climate goals and plans to meet those goals. To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the energy system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased penetration of renewable energy combined with investments in the grid and energy storage. PG&E Corporation and the Utility are also making progress on transitioning the gas system to cleaner fuels and supporting efforts to accelerate building electrification. The objective is to do so in an orderly manner to achieve a positive customer and community experience, while reducing natural gas system investments in targeted electrified communities. The impacts of climate change on the Utility's infrastructure are already a reality. Record-breaking extreme heat and heat waves are increasingly a regular occurrence throughout California. Peak electric loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage, and increasingly driven in the future from widespread progress in adoption of strategic electrification technologies. The Utility's assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise. 12 Climate change will also continue to intensify the potential for wildfires throughout California. The worsening conditions across California increase the likelihood and severity of wildfires, including those where the Utility's equipment may be alleged to be associated with the fire's ignition. Reducing risk will be even more important as climate change continues to exacerbate the risks facing the Utility. A key element of preparing the Utility for the physical risks of climate change is an updated and more detailed system-wide CVA of the Utility's assets, operations, and services, which the Utility expects to file with the CPUC in mid-2024. The CVA is expected to improve the Utility's understanding of its exposure to climate hazards and the sensitivity of assets and operations to these hazards. PG&E Corporation and the Utility continue to pursue policies and programs that enable safe, reliable, and affordable clean and resilient energy for their customers. As a result of actions already taken by PG&E Corporation and the Utility, the companies have:

For costs related to AROs, see "Asset Retirement Obligations" in Note 2 of the Notes to the Consolidated Financial Statements in Item 8. Human Capital

Employees and Contractors As of December 31, 2023, PG&E Corporation had 10 employees and the Utility had approximately 28,000 regular employees. Of the Utility's regular employees, approximately 17,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers ("IBEW") Local 1245; the Engineers and Scientists of California ("ESC") IFPTE 20; and the Service Employees International Union Local 24/7 ("SEIU"). The collective bargaining agreements in effect for the IBEW Local 1245, ESC Local 20, and SEIU United Service Workers West, are set to expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits. The IBEW, ESC, and SEIU represent approximately 63% of the Utility's employee workforce and support several areas of the Utility's business, including gas and electric operations. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2023. PG&E Corporation's employees are primarily at the executive management level. The Utility generally has a stable workforce. The Utility's turnover rates for 2023 and 2022 were 4.0% and 7.1%, respectively. Approximately 42% of PG&E Corporation's and the Utility's employees have a tenure of more than 10 years, with an average tenure of 11 years. Approximately 18% of PG&E Corporation's and the Utility's employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

The Utility's contractors and subcontractors include approximately 30,000 individuals from approximately 1,000 contractor companies. Human Capital Management PG&E Corporation's and the Utility's human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce. PG&E Corporation's and the Utility's Boards of Directors are responsible for overseeing management's development and execution of PG&E Corporation's and the Utility's human capital strategy. To build employee engagement, the Utility has a variety of both executive-level and employee-led initiatives and programs. PG&E Corporation's and the Utility's executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and virtues that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, innovation, and community service. The Utility conducts an annual employee survey to measure and improve employee engagement. 27 Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures. In addition, employees are required to complete annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities. In 2023, the Utility significantly expanded its training for supervisors. Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations. PowerPathway helps people throughout the Utility's service area, including women and military veterans, prepare and compete for high demand jobs in the utility and energy industry. Students receive approximately eight weeks of industry-informed curriculum to ensure the academic, job specific, employability skills and physical training necessary to effectively compete for entry-level employment. Programs may also include hands-on training and on-the-job training. PG&E Corporation and the Utility also provide integrated solutions and programs for employee health and wellness that encompass physical, mental, and financial health. These resources include several on-site or near-site health clinics, annual health screenings, health management tools, ergonomic support, and injury management programs, in addition to more traditional programs. PG&E Corporation's and the Utility's financial incentives offered to employees include a Short-Term Incentive Plan ("STIP"), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2023 STIP was focused on company objectives of safety, customer impact, and financial health.

Diversity, Equity, Inclusion, and Belonging PG&E Corporation's and the Utility's goal is to foster a diverse, equitable, and inclusive workforce culture where all employees find it enjoyable to work with and for PG&E Corporation and the Utility and feel they belong. These efforts are led by PG&E Corporation's and the Utility's Executive Vice President, Chief People Officer, in partnership with the executive team. The People and Compensation Committee of PG&E Corporation's Board of Directors reviews the companies' diversity, equity, inclusion, and belonging strategy, practices, and performance. Key elements of PG&E Corporation's and the Utility's approach include active programming to heighten cultural awareness, encourage understanding and appreciation of diversity, and integrate thoughtful content into training, development, and performance support resources. Additionally, the Utility's 12 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide employee programming, nominated employees lead efforts within their departments, and other specialized teams facilitate dialogue across the companies. In 2023, women, minorities, and military veterans accounted for approximately 26%, 50%, and 7%, respectively, of total PG&E Corporation and Utility employees. Approximately 9% of the Utility's employees are younger than 30, 62% are between the ages of 30 and 49, and 29% are 50 or older. 28

Electric Utility Operations The Utility generates electricity and provides electric transmission and distribution services throughout its service area in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides electricity, transmission, and distribution services in its service area. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. For more information, see "Competition" below.

Electricity Resources The Utility is required to maintain adequate capacity to meet its customers' demand for electricity ("load"), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. The following table shows the percentage of the Utility's estimated total net deliveries of electricity to customers in 2023 represented by each major electric resource, and further discussed below. The Utility's deliveries were primarily from renewable energy resources that qualify under California's RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California's RPS requirements and SB 100 goal is to serve 100% of retail electricity sales with GHG-free resources by 2045. For more information about California's RPS requirements and clean energy goals, see further below and in the Environmental Regulation section above.

Percent of customer retail sales (estimated Power Content Label) (2) Owned generation facilities Renewable (3) 2 %- %2 % Nuclear58 %(5)%53 % Large hydroelectric15 %(2)%13 %

Fossil fuel-fired (4) 25 %(25)%- % Total100 %(32)%68 % Third-party purchase agreements Renewable (3) 35 %(3)%32 % Fossil fuel-fired (4) 14 %(14)%- %

(1) This amount excludes electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers. (2) The allocation of "Others, net" in the "CEC Reporting Methodology Adjustment" and "Power Content Label" columns is consistent with current CEC guidelines as an adjustment mechanism to apply, as specified. Total reported generation and procurement volumes equate to actual electric retail sales. (3) Amounts include biopower (e.g., biogas, biomass), solar, wind, certain hydroelectric (i.e., 30MW or less), and geothermal facilities. The eligible renewable percentages above do not reflect RPS compliance, which is determined using a different methodology.

(4) Amounts consist primarily of natural gas facilities. (5) Amount is mainly comprised of net CAISO open market (sales)/purchases. (6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold. 29

The estimated total renewable deliveries as of December 31, 2023, shown above was 9,676 GWh and comprised of the following: TypePercent of Customer Retail Sales (estimated procurement)(1)

Generation TypeCounty LocationNumber of UnitsNet Operating Capacity (MW) Nuclear (1): Diablo CanyonSan Luis Obispo2 2,240 Hydroelectric (2): Conventional16 counties in northern and central California96 2,633

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility's regulators and the CAISO. 31 Electricity Distribution Distribution lines allow electricity to travel at lower voltages from substations directly to customers. The Utility's electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2023, approximately 26% are underground and approximately 74% are overhead), 67 transmission switching substations, and 752 distribution substations with a capacity of approximately 36,000 MVA. The Utility's distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, suitable for distribution to the Utility's customers. These distribution substations serve as the central hubs for the Utility's electric distribution network. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to customers. In some cases, third parties, such as municipal and other utilities, who generate or procure their own power rely upon the Utility's distribution facilities to deliver their power to them, so that they are able to resell the electricity. The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility's efforts to create a smarter, more resilient grid.

Industrial0.1294 0.1177 0.1075 Agricultural0.2984 0.2435 0.2104 Net plant investment per customer$10,720 $9,967 $9,199 (1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.

Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2023, the Utility's natural gas system consisted of approximately 44,200 miles of distribution pipelines, over 6,400 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one compressor station on its local transmission system that are used to move gas through the Utility's pipelines. The Utility's backbone transmission system is used to transport gas from the Utility's interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility's local transmission and distribution systems. The Utility has firm transportation agreements for the transportation of natural gas from various natural gas supply points and interconnection points to the Utility's natural gas transportation system. These agreements provide transportation service from western Canada to the United States-Canada border, from the United States-Canada border to an interconnection point with the Utility's natural gas transportation system at the Oregon-California border, from the U.S. Rocky Mountains to an interconnection point with the Utility's natural gas transportation system at the Oregon-California border, and from supply points in the southwestern United States to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona. (For more information regarding the Utility's natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility's gas transmission system. In 2019, the CPUC approved the discontinuation, through closure or sale, of operations at two of the Utility's owned and operated gas storage fields, Pleasant Creek and Los Medanos. The Utility expects to close on the sale of Pleasant Creek in 2024. The Utility plans to keep the Los Medanos storage field in operation as filed and approved in the 2023 GRC. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later for withdrawal. In addition, four independent storage operators are interconnected to the Utility's Northern California gas transmission system.

Subtotal6,196 6,055 4,958 Regulatory balancing accounts (2) 808 565 553 Total operating revenues$7,004 $6,620 $5,511 Selected Statistics: Average annual residential usage (Mcf)37 37 37

Regulatory Environment The Utility's business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is regulated primarily by the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and the OEIS. This section and the "Environmental Regulation" and the "Ratemaking Mechanisms" sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. For more information, see Item 1A. Risk Factors and "Regulatory Matters" in Item 7. MD&A. 16 PG&E Corporation is subject to the Public Utility Holding Company Act as a public utility holding company. The Public Utility Holding Company Act primarily obligates PG&E Corporation and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.