For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained in Item 7. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northernNorthern and centralCentral California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility’s service area is shown in the graphic below.

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 77 Beale Street, P.O. Box 770000, San Francisco,300 Lakeside Drive, Oakland, California 94177.94612. 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.

This 20202023 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 the section entitled “Forward-Looking Statements” above.

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 subject to the jurisdiction ofregulated 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.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. (ForFor more information, see Item 1A. Risk Factors and “Regulatory Matters” underin Item 7. MD&A.)

PG&E Corporation is a “public utility holding company” as defined undersubject to the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC.as a public utility holding company. The Public Utility Holding Company Act primarily obligates PG&E Corporation and its utility subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

The CPUC is a regulatory agency that regulates privately owned public utilities in California. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transmission and storage services. The CPUC has also has exercised jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electric and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

The CPUC enforces state and federal laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities.  The CPUC can impose penalties of up to $100,000 per day, per violation. The CPUC has widebroad discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations;violations, the type of harm caused by the violations and the number of persons affected;affected, and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged.

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation; but ifviolation. If it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, imposeSimilar to penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED hasimposed by the discretion either to address each violation in a distinct citation or to include multiple violations in a single citation regardless of whether the violations occurred in the same incident or are of a similar nature. PenaltyCPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and may not be recovered inthrough rates or otherwise directly or indirectly charged to customers. The CPUC has also authorized the SED to propose for CPUC approval administrative consent orders and administrative enforcement orders when the SED deems a formal order instituting investigation unnecessary.

The California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to wildfires and wildfire cost recovery, increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, the establishment of energy storage procurement targets, and the development of a state-wide electric vehicle charging infrastructure. The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. The CPUC also conducts audits and reviews of the Utility’s accounting, performance, and compliance with regulatory guidelines.

The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s 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. (ForFor more information on specific CPUC enforcement matters and CPUC-implemented laws and policies and the related impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Enforcement and Litigation Matters,” “Regulatory Matters,” “Legislative and Regulatory Initiatives”Initiatives,” and “Liquidity and Financial Resources” in Item 7. MD&A, and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the licensingsiting, construction, operation, maintenance, and safety obligations of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates the interconnections of the Utility’s transmission systems with other electric systems and generation facilities, the tariffs and conditions of service of regional transmission organizations, and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electric transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. The FERC’s approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property. The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. (ForFor more information on specific FERC requirements and their impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives”Initiatives,” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory.area. The CAISO controls the operation of the electric transmission system in most of California and a small part of Nevada and provides open access transmission service on a non-discriminatory basis. The CAISO is also responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generating capacity, ensuring that the reliability of the transmission system is maintained, and operating the wholesale power market in most of California and an interstate Energy Imbalance Market.energy imbalance market.

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 retired nuclear generating unitindependent spent fuel storage installation at Humboldt Bay. (SeeSee “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 capital expenditurescosts at Diablo Canyon, and substantial capital expenditurescosts could be required in the future. (ForFor more information about Diablo Canyon, see Item 1A1A. Risk Factors and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

The CEC is a California Energy Commission is the state’s primaryagency with responsibility for energy policy and planning agency.planning. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible forestablishes forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ and other load-serving entities’ electricity procurement plansprocurement. The CEC also promotes energy management and conservation programs, including setting standards for adopting building and appliance energy efficiency requirements.and load management programs.

The California Air Resources BoardCARB 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. (SeeSee “Environmental Regulation - Air Quality and Climate Change” below.)

The National Transportation Safety BoardNTSB 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. As a result

The California Geologic Energy Management Division is the state agency responsible for establishing and enforcing regulations for the operation of its investigation into the September 2010 San BrunoUtility’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 explosion,distribution, transmission, and underground storage facilities. The DOT has certified the NTSB issued 12 safety recommendationsCPUC to the Utility,administer oversight and also subsequently issued 28 safety recommendationscompliance with these regulations for the gas pipeline industry asentities it regulates in California.

The OEIS is a resultstate agency responsible for reviewing and approving the Utility’s WMP and for evaluating the Utility’s implementation of athe WMP. The OEIS is also responsible for reviewing and issuing the Utility’s annual safety study on integrity managementcertification, annually reviewing and approving the Utility’s executive compensation plan, conducting assessments of gas transmission pipelines in urban areas.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 and/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 andor 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. (ForFor more information see Item 1A. Risk Factors.)

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 capital 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. Generally, the Utility expectsFor more information about costs incurred to recover the cost of compliancecomply with government regulations from customers through its GRC proceedings, or other proceedings. To the extent the Utility incurs costs above authorized or incurs additional types of costs not included in rates, the Utility would expect to apply for recovery of such costs. Such recovery would be subject to the CPUC’s approval and could involve its reasonableness review.

The Utility’s facilities are subject to various regulations adopted by the U.S. Environmental Protection Agency (EPA),EPA, including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended. The Utility is also subject to the regulations adopted by other federal agencies responsible for implementing federal environmental laws. The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies. These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors. Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, monitoring and paying for the harm caused to natural resources, and paying for the costs of health studies.

The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former manufactured gas plantMGP sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.

For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions.

California’s AB 32,California laws and regulations have established the Global Warming Solutions Act of 2006, provides for the gradualfollowing targets:

The CARB has also approved various regulations to achieve the 2020 target, including GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy. The cap-and-trade program has been extended through 2030. The CARB plans to update the cap-and-trade regulation in 2024 and is considering reforms that would reduce overall allowance budgets to align with CARB’s 2022 Climate Change Scoping Plan.

In 2017, AB 398 extended the cap-and-trade program through January 1, 2031. During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Entities with a compliance obligation can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Complying entities may also satisfy a portion of their compliance obligation through the purchase of offset credits (e.g., credits for GHG reductions achieved by third parties, such as landowners, livestock owners, and farmers, that occur outside of the entities’ facilities through CARB-qualified offset projects such as reforestation or biomass projects). The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.

SB 32 (2016) requires that CARB ensureThe cap-and-trade program applies to the electric generation, large industrial, natural gas, petroleum, and transportation sectors. The Utility’s compliance obligation as a 40% reduction in GHGs by 2030 comparednatural gas supplier applies to 1990 levels. The California RPS program that requires utilitiesthe GHG emissions attributable to gradually increase the amountcombustion of renewable energynatural gas delivered to the Utility’s customers other than large natural gas delivery customers that are separately regulated as covered entities and have their customers is also expected to help reduce GHG emissions in California. In September 2018, SB 100 was signed into law, which accelerated the state’s 50% RPS target to December 31, 2026, increased the RPS target to 60% by December 31, 2030, and further amended the RPS statute to set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045. Additionally, Executive Order B-55-18 set a statewide goal to achieve economy-wide carbon neutrality by 2045 and to maintain net negative emissions thereafter. The Utility will be an active participant in regulatory proceedings to determine how the state will achieve carbon neutrality.own compliance obligations.

During 2020,2023, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment, consistent with the Utility’s commitment to a healthy environment and carbon neutral-energy system for all Californians.

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 regularly reviewsis 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 most relevant scientific literature onTriple 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.

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 risingsubstations is predicted to increase over time due to sea levels, major stormlevel 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 increasing temperatures and heatwaves, wildfires, drought and land subsidence, to help the Utility identify and evaluate climate change-related risks and develop the necessary resilience strategies. The Utility maintains emergency response plans and procedures to address a rangesuggest enhanced risk of near-term risks, including wildfires, extreme storms, and heat waves and uses its risk-assessment process to prioritize infrastructure investments for longer-term riskshydropower asset damage or failure associated with climate change. The Utilityflooding, which in the worst cases (e.g., uncontrolled water release) may have catastrophic impacts.

Climate change will also engagescontinue 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 leaders from business, government, academia,an expansion of areas that may become HFTD and non-profit organizationsan intensification of risk within HFTDs. Climate change may also result in increased potential of lines to share information and plancause ignitions or to require PSPS events, as well as the potential for the future.Utility’s equipment to sustain damage from wildfires of any origin.

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 is workinghas 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 currentmost vulnerable communities the Utility serves think about climate hazards and future impactsadaptation. This information will help the Utility plan adaptive climate action aligned with customer and community perspectives.

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. The Utility’s safety risks are included in its RAMP submittals withFor example, the CPUC. The Climate Resilience RAMP model indicated potential additional Utility safety consequences due to climate change, including in the near term. The Utility is conducting foundational work to help anticipate and plan for evolving conditions in terms of weather and climate-change related events. This work is guiding efforts to design a Utility-wide climate change risk integration strategy. This strategy will inform resource planning and investment, operational decisions, and potential additional programs to identify and pursue mitigations that will incorporate the resilience and safety of the Utility’s assets, infrastructure, operations, employees, and customers. The strategy will be informed by a multi-year, system-wide CVA to better understand how climate-driven natural hazards will impact the Utility’s assets, services, and operations.

PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.

California law established an RPS that requires load-serving entities,LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. In October 2015, the California Governor signed SB 350, the Clean EnergySee “Environmental Regulation - Air Quality and Pollution Reduction Act of 2015 into law. SB 350 became effective January 1, 2016, and increases the amount of renewable energy that must be delivered by most load-serving entities, 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.Climate Change” above. 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 from customersthrough rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.

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 as 35.6%to comprise 37% of total annual retail sales in 2020. In accordance with2023. Per the Power Content Label methodology based on current CEC guidelines presented in the table above, an estimated 35.6%34% of the Utility’s energy deliveries waswere from renewable energy sources.sources in 2023.

The estimated total 2020 renewable deliveries as of December 31, 2023, shown above werewas 9,676 GWh and comprised of the following:

As requiredEnergy storage improves system reliability and supports California’s decarbonization goals by California law, theintegrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, including energy storage procurement targets to be achieved by each load-serving entity under the CPUC jurisdiction, including the Utility. Under the adopted energy storage procurement framework,which the Utility iswas required to procure 580 MW of qualifying storage capacity by the end of 2021,2020, with all energy storage projects required to be operational by the end of 2024.

At December 31, 2020,2023, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below: