Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2017, the last business day of the most recently completed second fiscal quarter:

UNITS OF MEASUREMENT

1 Kilowatt (kW)			=			One thousand watts
1 Kilowatt-Hour (kWh)			=			One kilowatt continuously for one hour
1 Megawatt (MW)			=			One thousand kilowatts
1 Megawatt-Hour (MWh)			=			One megawatt continuously for one hour
1 Gigawatt (GW)			=			One million kilowatts
1 Gigawatt-Hour (GWh)			=			One gigawatt continuously for one hour
1 Kilovolt (kV)			=			One thousand volts
1 MVA			=			One megavolt ampere
1 Mcf			=			One thousand cubic feet
1 MMcf			=			One million cubic feet
1 Bcf			=			One billion cubic feet
1 MDth			=			One thousand decatherms

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GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2017
2022 Form 10-K			PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company's combinedthe Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2017 2022
AB 2021 Form 10-K			Assembly Bill PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2021
AFUDC AB			Assembly Bill
AFUDC			allowance for funds used during construction
ARO Amended Articles			Amended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020, and for PG&E Corporation, as amended by the Certificate of Amendment of Articles of Incorporation, filed on May 24, 2022
ARO			asset retirement obligation
ASU			accounting standard update issued by the FASB (see below) Financial Accounting Standards Board
CAISO Bankruptcy Code			the United States Bankruptcy Code
Bankruptcy Court			the U.S. Bankruptcy Court for the Northern District of California
CAISO			California Independent System Operator Corporation
California Water Board			California State Water Resources Control Board
Cal Fire	California Department of Forestry and Fire Protection
CARB CAPP			California Arrearage Payment Program
CARB			California Air Resources Board
CCA CARE			California Alternate Rates for Energy Program
CCA			Community Choice Aggregator
Central Coast Board CCPA			Central Coast Regional Water Quality Control Board California Consumer Privacy Act of 2018
CEC			California Energy Resources Conservation and Development Commission
CEMA			Catastrophic Event Memorandum Account
CO2 Chapter 11			carbon dioxide Chapter 11 of Title 11 of the U.S. Code
CPUC Chapter 11 Cases			the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Order			the order confirming the Plan, dated as of June 20, 2020, with the Bankruptcy Court
Corporation Revolving Credit Agreement			Credit Agreement, dated as of July 1, 2020, as amended, by and among PG&E Corporation, the several banks and other financial institutions or entities party thereto from time to time and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent
CHT			Customer Harm Threshold
CPIM			Core Procurement Incentive Mechanism
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CPUC			California Public Utilities Commission
CRRs CRR			congestion revenue rights
DER CVA			distributed energy resources climate vulnerability assessment
DIDF D&O Insurance			Distribution Investment Deferral Framework directors’ and officers’ liability insurance
DA			Direct Access
Diablo Canyon			Diablo Canyon nuclear power plant
DOE District Court			U.S.United States District Court for the Northern District of California
DOE			United States Department of Energy
DOGGR DOJ			DivisionUnited States Department of Oil, Gas and Geothermal Resources Justice
DOI DTA			U.S. Department of the Interior deferred tax asset
DRP DTSC			electric distribution resources plan
DTSC	California Department of Toxic Substances Control
EDA DWR			equity distribution agreement California Department of Water Resources
EMANI			European Mutual Association for Nuclear Insurance
EPA Emergence Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOEP			Enhanced Oversight and Enforcement Process

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EPA			U.S. Environmental Protection Agency
EPS			earnings per common share
EV EPSS			electric vehicle Enhanced Powerline Safety Settings
FASB EVM			Financial Accounting Standards Board enhanced vegetation management
FERC Exchange Act			Securities Exchange Act of 1934
FERC			Federal Energy Regulatory Commission
GAAP FHPMA			Fire Hazard Prevention Memorandum Account
Fire Victim Trust			The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be, funded
First Mortgage Bonds			bonds issued pursuant to the Indenture of Mortgage, dated as of June 19, 2020 between the Utility and The Bank of New York Mellon Trust Company, N.A., as amended and supplemented
FRMMA			Fire Risk Mitigation Memorandum Account
GAAP			U.S. Generally Accepted Accounting Principles
GHG			greenhouse gas
GRC GO			general order
GRC			general rate case
GT&S			gas transmission and storage
HSM HFTD			hazardous substance memorandum account high fire threat district
IOUs HSMA			investor-owned utility(ies) Hazardous Substance Memorandum Account
IRS IRC			Internal Revenue Service Code of 1986, as amended
LTIP IOUs			long-term incentive plan investor-owned utility(ies)
Kincade Amended Complaint			The amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Lakeside Building			300 Lakeside Drive, Oakland, California, 94612
LSEs			load serving entities
LTIP			Long-Term Incentive Plan
MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
NAV MGMA			Microgrids Memorandum Account
MGP			manufactured gas plants
NAV			net asset value
NDCTP			Nuclear Decommissioning Cost Triennial Proceeding
NEIL			Nuclear Electric Insurance Limited
NEM			net energy metering
NRC New Shares			Shares of PG&E Corporation common stock held by ShareCo that may be exchanged for Plan Shares as contemplated by the Share Exchange and Tax Matters Agreement
NRC			Nuclear Regulatory Commission
NTSB			National Transportation Safety Board
OES OEIS			State of California Office of Emergency Services Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OII			order instituting investigation

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OIR			order instituting rulemaking
ORA Pacific Generation			OfficePacific Generation LLC, a subsidiary of Ratepayer Advocates the Utility
PCIA PCAOB			Power Charge Indifference Adjustment Public Company Accounting Oversight Board (United States)
PD			proposed decision
PFM PERA			petition for modification Public Employees Retirement Association
PHMSA Plan			PipelinePG&E Corporation and Hazardous Materials Safety Administration the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
PSEP Plan Shares			pipeline safety enhancement plan Shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan

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QF PSPS			qualifying facility Public Safety Power Shutoff
RAMP QF			Risk Assessment Mitigation Phase Qualifying facilities
REITS RA			real estate investment trust Resource Adequacy
ROE Receivables Securitization Program			The accounts receivable securitization program entered into by the Utility on October 5, 2020, providing for the sale of a portion of the Utility’s accounts receivable and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions
ROE			return on equity
RPS ROU asset			renewable portfolio standard right-of-use asset
SB RPS			Senate Bill Renewables Portfolio Standard
SEC RTBA			Risk Transfer Balancing Account
RUBA			Residential Uncollectibles Balancing Account
SB			Senate Bill
SEC			U.S. Securities and Exchange Commission
SED Securities Act			The Securities Act of 1933, as amended
SED			Safety and Enforcement Division of the CPUC
SFGO			The Utility’s San Francisco General Office headquarters complex
Share Exchange and Tax Matters Agreement			Share Exchange and Tax Matters Agreement dated July 8, 2021 between PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust
ShareCo			PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV			PG&E AR Facility, LLC
Tax Act			Tax Cuts and Jobs Act of 2017
TE TO			transportation electrification transmission owner
TO TURN			transmission owner
TURN	The Utility Reform Network
Utility USFS			United States Forest Service
Utility			Pacific Gas and Electric Company
VIE(s) Utility Revolving Credit Agreement			Credit Agreement, dated as of July 1, 2020, as amended, by and among the Utility, the several banks and other financial institutions or entities party thereto from time to time and Citibank, N.A., as Administrative Agent and Designated Agent
VIE(s)			variable interest entity(ies)
WEMA VMBA			Vegetation Management Balancing Account
VSP			voluntary separation program
WEMA			Wildfire Expense Memorandum Account
Westinghouse Wildfire Fund			Westinghouse Electric Company, LLC statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WMBA			Wildfire Mitigation Balancing Account
WMCE			Wildfire Mitigation and Catastrophic Events
WMP			wildfire mitigation plan
WMPMA			Wildfire Mitigation Plan Memorandum Account

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FORWARD-LOOKING STATEMENTS

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

•the extent to which the Wildfire Fund and revised prudency standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires, including whether the Utility maintains an approved WMP and a valid safety certification and whether the Wildfire Fund has sufficient remaining funds;

•the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service area, including the wildfire that began on October 23, 2019 northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), the wildfire that began on September 27, 2020 in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), the wildfire that began on July 13, 2021 near the Cresta Dam in the Feather River Canyon in Plumas County, California (the “2021 Dixie fire”), the wildfire that began on September 6, 2022 near OxBow Reservoir in Placer County, California (the “2022 Mosquito fire”), and any other wildfires for which the causes have yet to be determined; the damage caused by such wildfires; the extent of the Utility’s liability in connection with such wildfires (including the risk that the Utility may be found liable for damages regardless of fault); investigations into such wildfires, including those being conducted by the CPUC; the outcome of the criminal proceeding initiated against the Utility in connection with the 2020 Zogg fire; potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action in respect of any such fire; the risk that the Utility is not able to recover costs from the Wildfire Fund or other third parties or through rates; and the effect on PG&E Corporation’s and the Utility’s reputations of such wildfires, investigations, and proceedings;

•the extent to which the Utility’s wildfire mitigation initiatives are effective, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; or to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; the cost of the program and the timing and outcome of any proceeding to recover such costs through rates; and any determination by OEIS that the Utility has not complied with its WMP;

•the impact of the Utility’s implementation of its PSPS program, and whether any fines, penalties, or civil liability for damages will be imposed on the Utility as a result; the costs in connection with PSPS events, the timing and outcome of any proceeding to recover such costs through rates, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

•the Utility’s ability to safely, reliably, and efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably;

•significant changes to the electric power and gas industries driven by technological advancements, electrification, and the transition to a decarbonized economy; the impact of reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs, DA providers, and legislative mandates to replace gas-fuel technologies; and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources and changing customer demand for its natural gas and electric services;

•cyber or physical attacks, including acts of terrorism, war, and vandalism, on the Utility or its third-party vendors, contractors, or customers (or others with whom they have shared data) which could result in operational disruption; the misappropriation or loss of confidential or proprietary assets, information or data, including customer, employee, financial, or operating system information, or intellectual property; corruption of data; or potential costs, lost revenues, litigation, or reputational harm incurred in connection therewith;

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•the impact of 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, mudslides, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, and other events that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the effectiveness of the Utility’s efforts to prevent, mitigate, or respond to such conditions or events; the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is able to procure replacement power; and whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events;

•existing and future regulation and federal, state or local legislation, their implementation, and their interpretation; the cost to comply with such regulation and legislation; and the extent to which the Utility recovers its associated compliance and investment costs, including those regarding:

◦wildfires, including inverse condemnation reform, wildfire insurance, and additional wildfire mitigation measures or other reforms targeted at the Utility or its industry;

◦the environment, including the costs incurred to discharge the Utility’s remediation obligations or the costs to comply with standards for GHG emissions, renewable energy targets, energy efficiency standards, distributed energy resources, and electric vehicles;

◦the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, and cooling water intake, and whether Diablo Canyon’s operations are extended; and the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

◦the regulation of utilities and their affiliates, including the conditions that apply to PG&E Corporation as the Utility’s holding company;

◦privacy and cyber security; and

◦taxes and tax audits;

•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 rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; the Utility’s application to transfer its non-nuclear generation assets to Pacific Generation and the potential sale of a minority interest in Pacific Generation; and the transfer of ownership of the Utility’s assets to municipalities or other public entities, including as a result of the City and County of San Francisco’s valuation petition;

•whether the Utility can control its operating costs within the authorized levels of spending; whether the Utility can continue implementing the Lean operating system and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the risks and uncertainties associated with inflation; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

•the outcome of current and future self-reports, investigations or other enforcement actions, or notices of violation that could be issued related to the Utility’s compliance with laws, rules, regulations, or orders applicable to its gas and electric operations; the construction, expansion, or replacement of its electric and gas facilities; electric grid reliability; audit, inspection and maintenance practices; customer billing and privacy; physical and cyber security protections; environmental laws and regulations; or otherwise, such as fines; penalties; remediation obligations; or the implementation of corporate governance, operational or other changes in connection with the EOEP;

•the risks and uncertainties associated with PG&E Corporation’s and the Utility’s substantial indebtedness and the limitations on their operating flexibility in the documents governing that indebtedness;

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•the risks and uncertainties associated with the timing and outcomes of PG&E Corporation’s and the Utility’s ongoing litigation, including appeals of the Confirmation Order; certain indemnity obligations to current and former officers and directors, as well as potential indemnity obligations to underwriters for certain of the Utility’s note offerings; three purported class actions that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509; the purported PSPS class action filed in December 2019; and other third-party claims, including the extent to which related costs can be recovered through insurance, rates, or from other third parties;

•the ability of PG&E Corporation and the Utility to securitize the remaining $1.385 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility;

•the risks and uncertainties associated with any future substantial sales of shares of common stock of PG&E Corporation by existing shareholders, including the Fire Victim Trust;

•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the IRC, as a result of which tax attributes could be limited;

•PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases and the financial and other restructuring undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;

•the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

•the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

•the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

•the risks and uncertainties associated with rising rates for the Utility’s customers;

•actions by credit rating agencies to downgrade PG&E Corporation’s or the Utility’s credit ratings;

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on energy demand in the Utility’s service area, the ability of the Utility to collect on customer receivables, the ability of the Utility to mitigate these effects, including with spending reductions, the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions caused either by illness of workers and their family members or workforce attrition related to potential new workplace regulations such as vaccine mandates; and

•the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors in this Form 10-K 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.

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PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors, including regarding dividends, at http://investor.pgecorp.com, under the “Wildfire and Safety Updates,” “News & Events: Events & Presentations,” and “Shareholders: Dividend Information” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident 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.

PART I

ITEM 1. BUSINESS

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 6. Selected8. 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.

At December 31, 2017, PG&E Corporation and the Utility had approximately 23,000 regular employees, approximately 20 of which were employees of PG&E Corporation.  Of the Utility’s regular employees, approximately 15,000 are covered by collective bargaining agreements with the local chapters of three labor unions:  the International Brotherhood of Electrical Workers; the Engineers and Scientists of California; and the Service Employees International Union.  The collective bargaining agreements currently in effect will expire on December 31, 2019. 

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. 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 freeEach 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 linksis a separate entity, with distinct creditors and claimants, and is subject to separate laws, rules, and regulations.

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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 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.  It is possible that these regulatory filings or information included therein could be deemed to be material information.  The information contained on this 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 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 “News & Events: Events & Presentations” tab,Consolidated Financial Statements in order to publicly disseminate such information. 

Item 8.

This 20172022 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, and results of operations, liquidity, and cash flows, see Item 1A. Risk Factors and the section entitled “Forward-Looking Statements” above.

Triple Bottom Line

PG&E Corporation’s and the Utility’s purpose is to deliver for their hometowns, serve the planet, and lead with love. In support of this purpose, the companies employ a Lean operating model designed to drive more effective and responsive decision-making, reduce the difficulties many coworkers face in their day-to-day work, and deliver better outcomes for customers and communities.

PG&E Corporation and the Utility measure their progress toward the purpose by considering their impact on the “triple bottom line” of people, planet, and prosperity, which is underpinned by performance; this consideration takes into account not only the economic value they create for customers and investors, but also their responsibility to social and environmental goals. The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities.

PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions. The Utility will continue to seek fair and timely regulatory treatment in order to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world class performance while delivering hometown service.

People

The people element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to their workforce, their customers, the residents of local communities in which the companies do business, and other stakeholders.

PG&E Corporation’s and the Utility’s goal is to continually reduce risk to keep customers, the communities they serve, and their workforce (both employees and contractors) safe. Their focus is on continuously building an organization where every work activity is designed to facilitate safe performance, every worker knows and practices safe behaviors, and every individual is encouraged to speak up and stop work if they see unsafe or risky behavior, and has confidence that their concerns and ideas will be heard and pursued. PG&E Corporation and the Utility are committed to significantly improving their safety performance by understanding their risks, prioritizing their work, using controls to reduce risks, and continuously measuring and improving risk reduction.

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitably-paid workforce. PG&E Corporation and the Utility place a high priority on delivering customer value and providing a hometown customer experience. The Utility’s customer-driven investment program is aimed at improving safety, increasing electric and gas reliability, and improving customer satisfaction.

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.

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The Utility strives to be prepared to continue to deliver 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 the consideration of forward-looking climate data and tools in its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate adaptation policy in California, and work directly with local governments and communities on adaptation solutions.

PG&E Corporation and the Utility have 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 electric 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 also plan to transition the gas system to cleaner fuels, increasingly target natural gas delivery for hard-to-electrify customer sectors, and support 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 beneficial 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.

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 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:

•Delivered clean electricity to customers in 2022 that was more than 95% GHG free.

•Helped customers avoid emissions and energy costs through robust energy efficiency programs.

•Awarded contracts for more than 3.3 GWs of battery energy storage to be deployed over the next several years, strengthening California’s grid efficiency and reliability.

•Installed approximately 340 charging ports for electric vehicles at schools, parks, public charging locations, and in support of fleets - with nearly half in disadvantaged communities - and received regulatory approval for new innovative pilots on vehicle grid integration, submetering, and dynamic rates.

•Brought the total number of interconnected private solar customers to more than 700,000 and supported more than 50,000 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 accelerating initiatives to meet its voluntary 2030 reduction goal.

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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 is required to offer for allocation or sale renewables portfolio standard-eligible (“RPS”) attributes that the Utility procured on behalf of customers that subsequently switched to non-Utility providers in order 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. For more information, see “Electric Integrated Resource Planning and Related Procurement” below.

Prosperity

The prosperity element of the triple bottom line represents PG&E Corporation’s and the Utility’s commitment to meeting their financial objectives and providing economic development opportunities and benefits in the communities they serve. Management believes clean energy should be affordable for and inclusive of all economic backgrounds.

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.

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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.

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•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.

Even as the Utility works to mitigate wildfire risk, it also works to reduce the impact of those mitigations on its customers, including making the PSPS program less disruptive through sectionalizing devices for both distribution and transmission lines, temporary generation applications, and implementation of microgrids which enable portions of the grid to safely isolate areas from the broader grid and energize them during outages. For example, in 2022, the Utility prepared 12 distribution microgrids to operate with temporary generation if needed.

In 2022, the Utility expanded the EPSS program to all high fire risk areas. In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for maximum wildfire ignition risk reduction when needed and enhancing reliability benefits when wildfire risk is low. In 2022, the Utility also began reviewing and adjusting settings to improve coordination among devices on a circuit to reduce the number of customers impacted by an outage. In 2023, the Utility will expand its deployment of advanced technology to detect low-current faults, which is expected to further decrease wildfire ignition risk.

PG&E Corporation and the Utility are continuing to invest in a safe and reliable gas system and are working toward targeted electrification, greening the gas supply, and shaping California energy policy. The Utility has focused on continuously improving its gas operations safety record. Since the San Bruno natural gas pipeline explosion in 2010, the Utility’s asset safety efforts have included replacing distribution mains and transmission pipelines, as well as strength testing transmission pipelines. The Utility uses in-line inspections to assess the integrity of transmission pipelines. The Utility also uses safety and control systems to monitor, gather, and process real-time data on its gas system. In 2022, the Utility’s gas operations had two workforce serious injuries and fatalities (“SIF-A”) incidents and reductions in the number of injuries that result in days away, restricted or transferred duty per 200,000 hours worked (“DART”). The Utility’s gas system has not had a safety-related incident that affected the public and resulted in a fatality or injury since 2015 or 2018, respectively.

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The Utility has engaged in educating employees, contractors, and the public regarding safe digging programs and practices for their awareness during construction and when digging near the Utility’s underground gas and electric assets. The Utility also installed safety devices that automatically detect increasing pressure on systems and stop the flow of gas to avoid outages and overpressure events. Additionally, the Utility continues to streamline its efforts to respond to outages on a timely basis. The Utility’s outage response is designed to keep the public safe while limiting customer outages and returning service safely and as quickly as possible.

The Utility’s generation operations have focused on safety and reliability. In 2022, the Utility’s nuclear and non-nuclear generation operations achieved zero SIF-A incidents and reductions in DART. Challenged by a drought year, the Utility scheduled dispatch and rescheduled outages to maximize availability during the summer months when demand for electricity is highest. The Utility is working to implement a comprehensive non-nuclear generation asset management strategy and further mature its outage and project management capabilities.

In 2022, the Utility achieved International Organization for Standardization (“ISO”) 55001 certification for its electric operations and generation asset management systems. The Utility also achieved ISO 55001 re-certification for its gas operations asset management. ISO 55001 certification required the Utility to demonstrate that it has policies and procedures to manage its assets responsibly and effectively.

Regulatory and Enforcement Environment 

The Utility'sUtility’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.  health, such as the NTSB and OEIS.

This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sectionsections 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.

PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC. PG&E Corporation and its 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.

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The California Public Utilities Commission

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'sUtility’s electric and natural gas distribution operations, electric generation, and natural gas transmission and storage services. The CPUC has also hasexercised jurisdiction over the Utility'sUtility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility'sUtility’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 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 $50,000$100,000 per day, per violation, for violations that occurred after January 1, 2012.  (The statutory maximum penalty for violations that occurred before January 1, 2012 is $20,000 per violation.) The CPUC has wide 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,violation; but if it assesses a penalty for a violation, it is requiredhas the authority to impose the maximum statutory penalty of $50,000,$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 to either 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 mustmay not be recovered in 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 OII unnecessary.

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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'sUtility’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 “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 16 of the Notes to the Consolidated Financial Statements in Item 1A. Risk Factors.) 

The 8.

Federal Energy Regulatory Commission and the California Independent System Operator

Corporation

The FERC has jurisdiction over the Utility'sUtility’s electric transmission revenue requirements and rates, the licensing of substantially all of the Utility'sUtility’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 systemsystems 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.

For 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” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 16 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 is responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generating capacity, and ensuring that the reliability of the transmission system is maintained.

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maintained, and operating the wholesale power market in most of California and an interstate energy imbalance market.

The Nuclear Regulatory Commission

Ratemaking Mechanisms

The Utility’s rates for electric and natural gas utility services are set at levels that are intended to allow the Utility to recover its costsMaterial Effects of providing service and a return on invested capital (“cost-of-service ratemaking”).  Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount that the Utility will be authorized to collect from its customers (“revenue requirements”).  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, tax, and financing expenses).  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, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings.  Similarly, the authorized rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding.  Other than its electric transmission and certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume.  Regulatory balancing accounts, or revenue adjustment mechanisms, are designed to allow the Utility to fully collect its authorized base revenue requirements.  Compliance with Governmental Regulations

Natural Gas Transmission and Storage Rate Cases

The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in the GT&S rate case. The CPUC generally conducts a GT&S rate case every three or four years.  Similar to the GRC, the CPUC approves the annual revenue requirements for the first year (or “test year”) of the GT&S rate case period and typically determines annual increases in revenue requirements for attrition years of the GT&S rate case period.  Parties in the Utility's GT&S rate case include the ORA and TURN, who generally represent the overall interests of residential customers, as well as other intervenors who represent other business, community, customer, environmental, and union interests.  The Utility filed the 2019 GT&S rate case application on November 17, 2017. (For more information, see “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” and “Regulatory Matters – 2019 Gas Transmission and Storage Rate Case” in Item 7. MD&A.)     

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 CPUC has authorized the Utility’s capital structure through 2019, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock.  The CPUC also set the authorized ROE through 2017 at 10.40% and 10.25% beginning on January 1, 2018 and reset the cost of debt to 4.89%.  The CPUC adopted an adjustment mechanism to allow the Utility’s capital structure and ROE to be adjusted if the utility bond index changes by certain thresholds on an annual basis.

(For more information, see “Regulatory Matters – CPUC Cost of Capital” in Item 7. MD&A.)

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 in rates in the TO rate case.  The Utility has historically filed a TO rate case every year.  The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision.  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.

Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California investor-owned electric utilities are responsible for procuring electrical capacity required to meet bundled customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electric contracts.  The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”).  In addition, the utilities are required to obtain CPUC approval of their bundled customer procurement plans based on long-term demand forecasts.  In October 2015, the CPUC approved the Utility’s most recent bundled customer procurement plan.  It was revised since its initial approval and will remain in effect as revised until superseded by a subsequent CPUC-approved plan.

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved bundled customer procurement plans without further after-the-fact reasonableness review by the CPUC.  The CPUC may disallow costs associated with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch.  Additionally, the CPUC may disallow the cost of replacement power procured due to unplanned outages at Utility-owned generation facilities.

The Utility recovers its electric procurement costs annually primarily through the energy resource recovery account.  (See Note 316 of the Notes to the Consolidated Financial Statements in Item 8.)  Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement.  The CPUC may adjust the Utility’s retail electric rates more frequently if the forecasted aggregate over-collections or under-collections in the energy resource recovery account exceed 5% of its prior year electric procurement and Utility-owned generation revenues.  The CPUC performs an annual compliance review of the transactions recorded in the energy resource recovery account.

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved procurement plan, to meet mandatory renewable energy targets, and to comply with resource adequacy requirements.  (For more information, see “Electric Utility Operations – Electricity Resources” below as well as Note 13 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 core procurement incentive mechanism 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 under-collections and over-collections taken into account in subsequent monthly rate changes. 

The core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.  Under the core procurement incentive mechanism, 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 in customers’ rates.  One-half of the costs above 102% of the benchmark are recoverable in customers’ 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 that shippers, including the Utility, pay for pipeline service, and the applicable Canadian tariffs are approved by the National Energy Board, a Canadian regulatory agency.  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.

Costs Associated with Public Purpose and Customer Programs

The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers. These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters.  Additionally, the CPUC has authorized the Utility to provide a discount rate for low-income customers, known as California Alternate Rates for Energy (“CARE”), which is subsidized by the Utility’s other customers.

Owned Generation Facilities

At December 31, 2017, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:

(1)The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  The NRC operating licenses expire in 2024 and 2025, respectively.  On January 11, 2018, the CPUC approved the Utility’s application to retire Unit 1 by 2024 and Unit 2 by 2025. (See “Diablo Canyon Nuclear Power Plant” in. Item 7. MD&A and Item 1A. Risk Factors.)

(2) The Utility’s hydroelectric system consists of 106 generating units at 66 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years.

(3) TheUtility’s large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW ), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW).  All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County.

Generation Resources from Third Parties.

The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan.  (See “Ratemaking Mechanisms” above.)  For more information regarding the Utility’s power purchase agreements, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission 

At December 31, 2017, the Utility owned approximately 19,200 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV.  The Utility also operated 92 electric transmission substations with a capacity of approximately 64,700 MVA.  The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, Alberta and British Columbia, and parts of Mexico.

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of our regulators. For example, in 2013, the Utility, MidAmerican Transmission, LLC, and Citizens Energy Corporation were selected by the CAISO to jointly develop a new 230-kV transmission line to address the growing power demand in the Fresno, Madera and Kings counties area.  However, the 2022 in-service date for the 70-mile line was subsequently postponed by the CAISO, and the CAISO has placed the project on hold.  The Utility has stopped all work on the project pending a decision from the CAISO that could defer or cancel the project.  A decision by the CAISO is expected by March 2018.  In addition, as a part of the CAISO's 2016-2017 planning efforts, the CAISO found that a number of lower-voltage transmission projects were no longer required and recommended cancelling or requiring further review in the 2017-2018 planning cycle.

Throughout 2017, the Utility upgraded several substations and re-conductored a number of transmission lines to improve maintenance and system flexibility, reliability and safety.  The Utility expects to undertake various additional transmission projects over the next several years to upgrade and expand the capacity of its transmission system to secure access to renewable generation resources and replace aging or obsolete equipment and improve system reliability.  The Utility also has taken steps to improve the physical security of its transmission substations and equipment.

Electricity Distribution

The Utility's electric distribution network consists of approximately 107,200 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 59 transmission switching substations, and 605 distribution substations, with a capacity of approximately 31,800 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, ranging from 44 kV to 2.4 kV, 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 end-users.  In some cases, the Utility sells electricity from its distribution facilities to entities, such as municipal and other utilities, that 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.

In 2017, the Utility continued to deploy its fault location, isolation, and service restoration circuit technology that involves the rapid operation of smart switches to reduce the duration of customer outages.  Another 92 circuits were outfitted with this equipment, bringing the total deployment to 882 of the Utility’s 3,200 distribution circuits.  The Utility plans to continue performing work to improve the reliability and safety of its electric distribution operations in 2018.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2015 to 2017 for electricity sold or delivered, including the classification of revenues by type of service.  No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2017, 2016 and 2015.

(1) These amounts include electricity provided to direct access customers and CCAs who procure their own supplies of electricity.

(2) This activity is primarily related to provisions for rate refunds and unbilled electric revenue, partially offset by other miscellaneous revenue items.

 (3)These amounts represent revenues authorized to be billed. 

Natural Gas Utility Operations

The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as core transport agents). When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers.  When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, more than 95% of core customers, representing approximately 80% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility generally does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility that the Utility has a power purchase agreement with that includes its generation fuel expense.  The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers. The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.

Natural Gas Supplies

The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.  The Utility can also receive natural gas from fields in California.  The Utility purchases natural gas to serve its core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have varied generally based on market conditions.  During 2017, the Utility purchased approximately 291,100 MMcf of natural gas (net of the sale of excess supply of gas).  Substantially all of this natural gas was purchased under contracts with a term of one year or less.  The Utility’s largest individual supplier represented approximately 14% of the total natural gas volume the Utility purchased during 2017.

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, 2017, the Utility’s natural gas system consisted of approximately 42,800 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 small station on its local transmission system that are used to move gas through the Utility’s pipelines.  The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, 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 delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. interconnecting downstream with TransCanada Foothills Pipe Lines Ltd., B.C. System.  The Foothills system interconnects at the border to the pipeline system owned by Gas Transmission Northwest, LLC, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility also has firm transportation agreements with Ruby Pipeline, LLC to transport natural gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border.  Similarly, the Utility has firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport natural gas 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.  The Utility also has a transportation agreement with Kern River Gas Transmission Company to transport gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas system in the area of Daggett, California.  (For more information regarding the Utility’s natural gas transportation agreements, see Note 13 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 transmission system. 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 withdrawal. In addition, four independent storage operators are interconnected to the Utility's northern California transmission system.  Changes to gas storage safety requirements by DOGGR have led the Utility to develop and propose in its 2019 GT&S rate case application a natural gas storage strategy which includes the discontinuation (through closure or sale) of operations at two gas storage fields.  (For more information, see “Regulatory Matters” in Item 7. MD&A.)

In 2017, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and continued its work on the final NTSB recommendation from its San Bruno investigation to hydrostatically test all high consequence pipeline mileage.  The Utility currently plans to complete this NTSB recommendation by 2022 for remaining short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines.

Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2015 through 2017 (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 2017, 2016 and 2015.

Competition

Competition in the Electricity Industry

California law allows qualifying non-residential electric customers of investor-owned electric utilities to purchase electricity from energy service providers rather than from the utilities up to certain annual and overall GWh limits that have been specified for each utility.  This arrangement is known as “direct access.”  In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate and/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 direct access customers, although these customers can choose to obtain metering and billing services from 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 direct access and CCA customers while they were the Utility’s customers.  The Utility remains the electricity provider of last resort for these customers.  

The Utility is also impacted by the increasing viability of distributed generation and energy storage.  The levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering (“NEM”), which allows self-generating customers to receive bill credits at the full retail rate, are increasing.  These factors result in a shift of cost responsibility for grid and related services to other customers of the Utility.  For example, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer NEM, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, puts upward rate pressure on remaining customers.  New rules and rates became effective for new NEM customers of the Utility in December 2016.  New NEM customers are required to pay an interconnection fee, comply with time of use rates, and are required to 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 remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers.  The CPUC has indicated that it intends to revisit these rules in 2019.

Further, in some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, may seek to acquire the Utility’s distribution facilities, generally through eminent domain.  These same entities may, and sometimes do, construct duplicate distribution facilities to serve existing or new Utility customers.

The effect of such types of retail competition generally is to reduce the amount of electricity purchased by customers from the Utility.

The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.  The FERC's transmission planning requirements rules, effective in 2011, removed the incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities and mandated regional and interregional transmission planning.  In 2014, the FERC approved the CAISO's process for regional planning and competitive solicitations and the CAISO's interregional planning process.

(For risks in connection with increasing competition, see Item 1A. Risk Factors.)

Competition in the Natural Gas Industry

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.  The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Environmental Regulation