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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________
FORM 10-K
(Mark One) 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2021
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to  ___________  
Commission
File Number
Exact Name of Registrant
as Specified In Its Charter
State or Other Jurisdiction of
Incorporation or Organization
IRS Employer
Identification Number
1-12609PG&E CORPORATIONCalifornia94-3234914
1-2348PACIFIC GAS AND ELECTRIC COMPANYCalifornia94-0742640
pcg-20211231_g1.jpg
pcg-20211231_g2.jpg
77 Beale Street77 Beale Street
P.O. Box 770000P.O. Box 770000
San Francisco,California94117San Francisco,California94117
(Address of principal executive offices) (Zip Code)(Address of principal executive offices) (Zip Code)
415973-1000415973-1000
(Registrant’s telephone number, including area code)(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common stock, no par valuePCGThe New York Stock Exchange
Equity UnitsPCGUThe New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 5% series A redeemablePCG-PENYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemablePCG-PDNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemablePCG-PGNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemablePCG-PHNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemablePCG-PINYSE American LLC
First preferred stock, cumulative, par value $25 per share, 6% nonredeemablePCG-PANYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemablePCG-PBNYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemablePCG-PCNYSE American LLC

Securities registered pursuant to Section 12(g) of the Act: none



Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
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.
PG&E CorporationPacific Gas and Electric Company
Large accelerated filerLarge accelerated filer
Non-accelerated filerNon-accelerated filer
Smaller reporting companySmaller reporting company
Accelerated filerAccelerated filer
Emerging growth companyEmerging growth company
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.
PG&E Corporation:
Pacific Gas and Electric Company:
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of
the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report.
PG&E Corporation:
Pacific Gas and Electric Company:
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
PG&E Corporation:YesNo
Pacific Gas and Electric Company:YesNo



Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2021, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation common stock
                    $20,185 million
Pacific Gas and Electric Company common stock                    Wholly owned by PG&E Corporation
Common Stock outstanding as of February 4, 2022: 
PG&E Corporation:2,463,891,104*
Pacific Gas and Electric Company:
264,374,809
*Includes 437,743,590 shares of common stock held by PG&E ShareCo LLC, a wholly-owned subsidiary of PG&E Corporation, and 40,000,000 shares of common stock held by Pacific Gas and Electric Company.



DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the Joint Proxy Statement relating to the 2021 Annual Meetings of ShareholdersPart III (Items 10, 11, 12, 13 and 14)




Contents
4



5


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.
2021 Form 10-KPG&E Corporation’s and Pacific Gas and Electric Company’s combined Annual Report on
Form 10-K for the year ended December 31, 2021
ABAssembly Bill
AFUDCAllowance for Funds Used During Construction
Amended ArticlesAmended and Restated Articles of Incorporation of PG&E Corporation and the Utility, each filed on June 22, 2020
AROasset retirement obligation
ASUaccounting standard update issued by the FASB
Bankruptcy Codethe United States Bankruptcy Code
Bankruptcy Courtthe U.S. Bankruptcy Court for the Northern District of California
BPPbundled procurement plan
CAISOCalifornia Independent System Operator Corporation
Cal FireCalifornia Department of Forestry and Fire Protection
CAPPCalifornia Arrearage Payment Program
CARBCalifornia Air Resources Board
CARECalifornia Alternate Rates for Energy Program
CCACommunity Choice Aggregator
CCPACalifornia Consumer Privacy Act of 2018
CECCalifornia Energy Resources Conservation and Development Commission
CEMACatastrophic Event Memorandum Account
Chapter 11Chapter 11 of Title 11 of the U.S. Code
Chapter 11 Casesthe voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
Confirmation Orderthe order confirming the Plan, dated as of June 20, 2020 with the Bankruptcy Court
CHTCustomer Harm Threshold
CPIMCore Procurement Incentive Mechanism
CPPMACOVID-19 Pandemic Protections Memorandum Account
CPUCCalifornia Public Utilities Commission
CRRscongestion revenue rights
CVAClimate Vulnerability Assessment
DADirect Access
Diablo CanyonDiablo Canyon nuclear power plant
DOEU.S. Department of Energy
DTAdeferred tax asset
DTSCDepartment of Toxic Substances Control
EMANIEuropean Mutual Association for Nuclear Insurance
Emergence Date
July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
EOExecutive Order
EOEPEnhanced Oversight and Enforcement Process
EPAU.S. Environmental Protection Agency
EPSearnings per common share
EPSS
Enhanced Powerline Safety Settings
EVelectric vehicle
EVMenhanced vegetation management
Exchange ActSecurities Exchange Act of 1934
FASBFinancial Accounting Standards Board
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FERCFederal Energy Regulatory Commission
FHPMAFire Hazard Prevention Memorandum Account
Fire Victim TrustThe 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
FRMMAFire Risk Mitigation Memorandum Account
GAAPU.S. Generally Accepted Accounting Principles
GHGgreenhouse gas
GOgeneral order
GRCgeneral rate case
GT&Sgas transmission and storage
HFTDhigh fire-threat districts as set forth in the CPUC Fire-Threat Map
HSMhazardous substance memorandum account
IRCInternal Revenue Code
IRPIntegrated Resource Planning
IOUsinvestor-owned utility(ies)
Kincade Amended ComplaintThe amended criminal complaint filed by the Sonoma County District Attorney’s Office on January 28, 2022 in connection with the 2019 Kincade fire
Kincade ComplaintThe criminal complaint filed by the Sonoma County District Attorney’s Office on April 6, 2021 in connection with the 2019 Kincade fire
Lakeside Building300 Lakeside Drive, Oakland, California, 94612
LIBORLondon Interbank Offered Rate
LSELoad-serving entity
LTIPLong-Term Incentive Plan (including the PG&E Corporation 2021 Long-Term Incentive Plan and its predecessor, the PG&E Corporation 2014 Long-Term Incentive Plan)
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
MGMAMicrogrids Memorandum Account
MGPmanufactured gas plants
the Monitorthird-party monitor retained by the Utility as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAVnet asset value
NEILNuclear Electric Insurance Limited
NEMnet energy metering
NRCNuclear Regulatory Commission
NTSBNational Transportation Safety Board
OEISOffice of Energy Infrastructure Safety (successor to the Wildfire Safety Division of the CPUC)
OIIorder instituting investigation
OIRorder instituting rulemaking
PCAOBPublic Company Accounting Oversight Board (United States)
PDproposed decision
PERAPublic Employees Retirement Association
Petition DateJanuary 29, 2019
Plan
PG&E Corporation and the Utility, Knighthead Capital Management, LLC, and Abrams Capital Management, LP Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020
PODPresiding Officer’s Decision
PSPSPublic Safety Power Shutoff
QFQualifying facilities
RAMPRisk Assessment Mitigation Phase
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RAResource Adequacy
ROEreturn on equity
ROU assetright-of-use asset
RPSRenewables Portfolio Standard
RSArestructuring support agreement
RTBARisk Transfer Balancing Account
RUBAResidential Uncollectibles Balancing Account
SBSenate Bill
SECU.S. Securities and Exchange Commission
SEDSafety and Enforcement Division of the CPUC
SFGOThe Utility’s San Francisco General Office headquarters complex
ShareCoPG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation
SPV
PG&E AR Facility, LLC
Tax ActTax Cuts and Jobs Act of 2017
TCCOfficial Committee of Tort Claimants
TCC RSARestructuring Support Agreement dated December 6, 2019 with the TCC and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended
TOtransmission owner
TURNThe Utility Reform Network
UtilityPacific Gas and Electric Company
VIE(s)variable interest entity(ies)
VMBAVegetation Management Balancing Account
WEMAWildfire Expense Memorandum Account
Wildfire Fundstatewide 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
Wildfires OIIOrder Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
WMBAWildfire Mitigation Balancing Account
WMCEWildfire Mitigation and Catastrophic Events
WMPwildfire mitigation plan
WMPMAWildfire Mitigation Plan Memorandum Account
Zogg Complaint
The criminal complaint filed by the Shasta County District Attorney’s Office on September 24, 2021

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,” “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 recoverability standard under AB 1054 effectively mitigates 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;
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the risks and uncertainties associated with wildfires that have occurred or may occur in the Utility’s service territory, 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”), 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 and various district attorney’s offices; the outcome of the criminal proceedings initiated against the Utility in connection with the 2019 Kincade fire, the 2020 Zogg fire, and three other fires; 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 insurance, from the Wildfire Fund 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; to retain or contract for the workforce necessary to execute its WMP; the effectiveness of its system hardening, including undergrounding; and the cost of the program and the timing and outcome of any proceeding to recover such costs through rates;

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;

the availability, cost, coverage, and terms of the Utility’s insurance, including insurance for wildfire, nuclear, and other liabilities, the timing of any insurance recoveries, and recovery of the costs of such insurance or, in the event liabilities exceed insured amounts, the ability to recover uninsured losses through rates or from other third parties;

significant changes to the electric power and gas industries driven by technological advancements and a decarbonized economy;

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, or reputational harm incurred in connection therewith;

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 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;

the ability of the Utility to meet the conditions in its corrective action plan and exit the EOEP;

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the timing and outcome of 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 EVs;

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

the regulation of utilities and their holding companies, including the conditions imposed on PG&E Corporation when it became the Utility’s holding company and whether the Utility can make distributions to PG&E Corporation; 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;

whether the Utility can control its operating costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve projected savings; the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; 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 cybersecurity protections; environmental laws and regulations; or otherwise, such as fines, penalties, remediation obligations, the transfer of ownership of the Utility’s assets to municipalities or other public entities, 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;

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 appeal of the FERC’s order denying rehearing on March 17, 2020 granting the Utility a 50-basis point ROE incentive adder for continued participation in the CAISO; the debarment proceeding; 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 (i) the remaining $2.4 billion of fire risk mitigation capital expenditures that were or will be incurred by the Utility and (ii) $7.5 billion of costs related to the multiple wildfires that began on October 8, 2017 and spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”), in a financing transaction that is designed to be rate neutral to customers;

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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 impact that 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, have on the Utility’s ability to make and recover its investments through rates and earn its authorized ROE, 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;

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 the Utility’s ability to accurately forecast major capital expenditures, weighted average annual rate base and expense reduction associated with implementation of the Lean operating system;

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 territory, 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;

increased employee attrition as a result of the challenging political and operating environment facing PG&E Corporation and the Utility;

whether PG&E Corporation’s and the Utility’s counterparties are available and able to meet their financial and performance obligations with respect to contracts, credit agreements, and financial instruments, which could be affected by disruptions in the global supply chain caused by the COVID-19 pandemic or otherwise; 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 below and a detailed discussion of these matters contained in Item 7. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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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 at http://investor.pgecorp.com, under the “Chapter 11,” “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. Specifically, within two hours during business hours or four hours outside of business hours of the determination that an incident is attributable or allegedly attributable to the Utility’s electric facilities and has resulted in property damage estimated to exceed $50,000, a fatality or injury requiring overnight in-patient hospitalization, or significant public or media attention, the Utility is required to submit an electric incident report including information about such incident. 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.


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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 Northern and Central 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.
pcg-20211231_g3.jpg
PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below in Item 8. Financial Statements and Supplementary Data.

The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.

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

Over the past several years, Northern California has experienced major wildfires. For more information about material wildfires, see Item 7. MD&A, and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

This 2021 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors and “Forward-Looking Statements” above.

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 human struggle 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.

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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 equitable 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. Management believes that integrating and managing climate change and other environmental considerations in the companies’ business strategies creates long-term value for PG&E Corporation and the Utility, and for their customers, communities, coworkers, and other stakeholders. Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility’s business and economic opportunity for the communities it serves.

The Utility 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 are an important enabler of California’s effort to reduce GHG emissions. California has set a goal to achieve economy-wide carbon neutrality no later than 2045. SB 100 increased California’s RPS target to 60% by the end of 2030 and requires 100% of retail sales to come from eligible renewables or zero-carbon resources by the end of 2045.

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 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. 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 a 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.
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The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California utilities also are experiencing increasing deployment by customers and third parties of distributed energy resources, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and load management technologies. These developments will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, and EV infrastructure. To this end, the CPUC is conducting proceedings to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources and consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator.

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:

Exceeded California’s renewable portfolio standards goal for each utility (including the Utility) to deliver 33 percent of eligible renewable energy by the end of 2020, and delivered clean electricity to customers in 2021 that was more than 90% GHG free.

Helped customers avoid emissions through energy efficiency programs, supporting California’s goal to double energy efficiency in existing buildings by 2030.

Awarded contracts for more than 1.7 GWs of battery energy storage, strengthening California’s grid efficiency and reliability.

Installed approximately 5,000 charging ports for EVs at workplaces and multi-family dwellings, including installing 39% of these charging ports in disadvantaged communities, and also offered programs to support medium- and heavy-duty fleets and public fast charging in support of California’s goal of 100 percent sales of light-duty zero-emission vehicles by 2035.

Brought the total number of interconnected private solar customers to more than 600,000 and supported more than 33,000 customers who have installed battery storage at their homes or businesses.

Pursued decarbonization initiatives for the Utility’s natural gas delivery system, including working to interconnect several renewable natural gas projects.

Looking ahead, the Utility expects its GHG-free energy supply mix of renewable, large hydroelectric, and nuclear generation resources to remain elevated while Diablo Canyon continues to operate. Once Diablo Canyon ceases operations in 2025, the Utility expects its percentage of GHG-free electricity to decrease substantially. 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. 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 works to meet California’s IRP GHG emissions reduction targets and its RPS target. For more information, see “Integrated Resource Planning 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.

The Utility operates under a “cost of service ratemaking model,” which means that rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and have the opportunity to earn a return on invested capital. Under cost of service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs.

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In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). Revenue authorized by the CPUC through GRC proceedings is intended to provide the Utility a reasonable opportunity to recover its costs and earn a return on its investments in generation and distribution assets and general plant (also referred to as “rate base”) on a forecast basis. 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, taxes, 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 and natural gas for customers and to administer public purpose and customer programs.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

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 (referred to as “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. The Utility has initiated a program to reduce its spending on operations and maintenance.

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 $2 billion by the end of 2023. 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. Additionally, 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. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 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. For more information, see “Dividends” in Item 7. MD&A.

Total capital expenditures (including accruals) recorded in 2021 were $8.6 billion. The Utility’s total capital expenditures (including accruals) are forecasted to be between $7.8 billion and $8.9 billion for 2022, between $7.9 billion and $10.4 billion for 2023, between $7.9 billion and $10.7 billion for 2024, between $8.0 billion and $11.3 billion for 2025, and between $8.1 billion and $12.0 billion for 2026. 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.

The Utility expects to make additional CPUC 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 expenditures to be included in a later stage of the 2023 GRC. The 2023 through 2026 currently above authorized capital spending levels are primarily for additional 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.

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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, such as the OIR to Revisit Net Energy Metering Tariffs, 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 2021, relative to 2020. The Utility is addressing this customer rate pressure with cost reductions through increased efficiency, including efficiency driven by implementing the Lean operating system, improving its work management, identifying additional opportunities to convert expenses to capital expenditures, and an improved organizational design. 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 2020, the Utility spent $3.9 billion with certified diverse suppliers, representing 38.9% of its total spend.

Performance: Underpinning The Triple Bottom Line

PG&E Corporation and the Utility are transitioning to the Lean operating system, which includes four basic “plays”: visual management, operating reviews, problem solving and standard work. PG&E Corporation and the Utility have implemented the first two plays in 2021 and expect to roll out the second two plays in 2022. Visual management allows teams to see how they are performing against their most important metrics using real-time data. During 2021, PG&E Corporation and the Utility have set up over 2,000 daily operating reviews, beginning with crews closest to the work and cascading up to 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. For instance, the Lean operating system helped the Utility identify patterns in the conditions of ignitions and led to the implementation of EPSS. 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.

PG&E Corporation and the Utility have implemented a regional operating model to place more co-workers and operational leadership closer to their customers. The purposes of regionalization are to address local issues faster; reduce outage response times; create faster interconnections for customers connecting solar or distributed energy to the grid; and build stronger relationships and information flow between the companies and their customers.

California has experienced unprecedented weather conditions in recent years and the Utility’s service territory 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: In 2021, the Utility implemented the EPSS program, which adjusts the sensitivity of circuit protection devices on certain power lines to de-energize them more rapidly in the event of a disturbance to help prevent potential ignitions. After EPSS was initiated, CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average.

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 strategic de-energizations of circuits and transmission lines.

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. In addition, the Utility operates an EVM program for distribution facilities in HFTD areas. 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 have become more thorough, standardized, digitized, and verifiable. The Utility uses risk-informed inspection cycles. In 2021, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections.
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System hardening: System hardening entails replacing or eliminating existing distribution lines in HFTDs and installing stronger and more resilient equipment. Hardening methods include replacing bare overhead conductor with covered conductor and installing stronger poles, removing the line and serving our customers through remote grids, or converting the line from overhead to underground. In 2021, the Utility announced a commitment to underground 10,000 miles of electric distribution lines in HFTDs, which will eliminate ignition risks from overhead vegetation or wind-induced equipment failures in those areas and help reduce the need for vegetation management.

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 microgrid pilot technologies. For example, in 2021, the CPUC authorized the Utility to prepare 10 substations to form microgrids in the event of PSPS outages impacting the transmission lines feeding those substations, in addition to nine other distribution microgrids that the Utility made ready to operate in 2021. Two of the distribution microgrids piloted battery storage and a linear generator in a hybrid configuration with diesel generation to assist in energizing the microgrids when needed. Through these and other mitigation actions, PSPS events in 2021 impacted 78% fewer customers on average than PSPS events in 2019. The Utility also brought online its first “remote grid” in 2021, which allows 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 impacted customers. The Utility is pursuing the development of additional remote grid projects.

In 2021, the Utility also worked to reduce the impact of EPSS by adjusting the sensitivity of devices to reduce the likelihood of an outage, improving coordination between its devices to reduce the size of outages, and improving internal coordination of patrol crews for faster restoration times. In 2022, the Utility plans to expand the scope of the EPSS program to all HFTD areas.

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 2021, the Utility’s gas operations achieved zero 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”). As of the date of this filing, the Utility’s gas system has not had a public safety-related incident that resulted in a fatality or injury since 2015 or 2018, respectively.

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 timely. 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 2021, the Utility’s 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 generation asset management strategy and further mature its outage and project management capabilities.

Regulatory Environment 

The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is regulated primarily by the FERC and the NRC. The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and OEIS.

This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. For more information, see Item 1A. Risk Factors and “Regulatory Matters” in Item 7. MD&A.

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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.

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’s electric and natural gas distribution operations, electric generation, and natural gas transmission and storage services. The CPUC also has exercised jurisdiction over the Utility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility’s electric and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

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

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation; but if it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued. Similar to penalties imposed by the CPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and may not be recovered 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.

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 EV charging infrastructure. The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. The CPUC also conducts audits and reviews of the Utility’s accounting, performance, and compliance with regulatory guidelines.

The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. For more information on specific CPUC enforcement matters and CPUC-implemented laws and policies and the related impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Enforcement and Litigation Matters,” “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7. MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Federal Energy Regulatory Commission and California Independent System Operator Corporation

The FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates the interconnections of the Utility’s transmission systems with other electric systems and generation facilities, the tariffs and conditions of service of regional transmission organizations, and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electric transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. The FERC’s approval is also required under Federal Power Act Section 203 before undertaking certain transactions, including most mergers and consolidations, certain transactions that result in a change in control of a utility, purchases of utility securities and dispositions of utility property. The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. 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 15 of the Notes to the Consolidated Financial Statements in Item 8.

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

Nuclear Regulatory Commission

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

Other Regulators

The California Energy Commission is California’s primary energy policy and planning agency. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans and for adopting building and appliance energy efficiency requirements.

The CARB is the state agency responsible for setting and monitoring GHG and other emission limits. The CARB is also responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California. See “Environmental Regulation - Air Quality and Climate Change” below.

The NTSB is an independent U.S. government investigative agency responsible for civil transportation accident investigations, including pipeline accidents. The NTSB also conducts special investigations and safety studies, and issues safety recommendations to prevent future accidents.

The California Geologic Energy Management Division is the state agency responsible for establishing and enforcing regulations for the operation of the Utility’s underground gas storage wells.

The OEIS is a state agency responsible for reviewing and approving the Utility’s WMP and for evaluating the Utility’s implementation of the WMP.

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In addition, the Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy or use public property for the operation of the Utility’s business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. For more information see Item 1A. Risk Factors.

Third-party Monitors

On April 12, 2017, the Utility retained the Monitor at the Utility’s expense as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, which sentenced the Utility to, among other things, a five-year corporate probation period and oversight by the Monitor for a period of five years.  On January 25, 2022, the period of probation expired and the Monitor’s oversight of the Utility ended. For more information see Item 1A. Risk Factors and “US District Court Matters and Probation” under “Enforcement and Litigation Matters” in Item 7. MD&A.

Additionally, as a condition to its approval of the Plan, the CPUC required the appointment of an independent safety monitor (the “Independent Safety Monitor”) for a term of five years, subject to extension if the CPUC determines that the Utility’s safety conditions would benefit from an Independent Safety Monitor’s continued involvement. On January 28, 2022, the CPUC announced that it had selected Filsinger Energy Partners to serve as the Independent Safety Monitor. According to the scope of work authorized by the CPUC, the Independent Safety Monitor will (1) monitor and alert CPUC staff whether the Utility is implementing its highest priority and risk-driven safety mitigations and (2) monitor the Utility’s safety-related recordkeeping and record management systems. In addition to confidential updates to the CPUC staff regarding safety-related concerns, the Independent Safety Monitor will also provide public summary reports of its activities to the CPUC every six months.

Material Effects of Compliance with Governmental Regulations

As indicated above, the Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. Compliance with such extensive government regulations requires substantial expenditures and has had in the past and may continue to have in the future a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position. Generally, the Utility expects to recover the cost of compliance with government regulations through rates in its GRC proceedings, or other proceedings. To the extent the Utility incurs costs above authorized or incurs additional types of costs not included in rates, the Utility would expect to apply for recovery of such costs. Such recovery would be subject to the CPUC’s approval and could involve its reasonableness review.

Costs incurred in 2021 included costs in connection with upgrading and maintaining the Utility’s electric and natural gas infrastructure in accordance with CPUC and federal requirements, participating in the Wildfire Fund under AB 1054, execution of wildfire mitigation initiatives, the licensing and other regulations of the FERC, environmental regulations, clean energy standards, regulations regarding Diablo Canyon, and various other generation, distribution and storage regulations, the amount of which was substantial.

If the Utility is unable to recover these costs or incurs fines or penalties as a result of non-compliance with such laws and regulations, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position could be materially impacted. For more information, see Item 1A. Risk Factors, “Regulatory Matters” in Item 7. MD&A, and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8.

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Environmental Regulation

The Utility’s operations are subject to extensive federal, state, and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of activities, including the remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of CO2 and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. See Item 1A. Risk Factors. Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a ratemaking mechanism described in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

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

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

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

Air Quality and Climate Change

The Utility’s electric generation plants, natural gas pipeline operations, vehicle fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter, and other emissions.

Federal Regulation

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

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Tackling the climate crisis is a key priority of the Biden Administration, and the Administration has signaled its intent to use its executive and regulatory authorities to reduce emissions in line with science-based targets. On January 20, 2021, President Biden issued an EO directing the EPA to consider suspending, revising or rescinding the Trump Administration’s rule for methane emissions from new sources in the oil and gas sector and propose a companion regulation for existing sources, including the transmission, processing and storage segments of the industry. For power plants, the EPA is expected to propose a more stringent GHG standard for existing sources in the wake of challenges to the Trump Administration’s Affordable Clean Energy rule.

State Regulation

California’s AB 32, the Global Warming Solutions Act of 2006, provided for the gradual reduction of state-wide GHG emissions to 1990 levels by 2020. The CARB has approved various regulations to achieve the 2020 target, including GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy.

The cap-and-trade program’s first compliance period, which began on January 1, 2013, applied to the electric generation and large industrial sectors. In the subsequent compliance period, which began on January 1, 2015, the scope of the regulation was expanded to include the natural gas and transportation sectors, effectively covering all of the state economy’s major sectors through 2020. The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than large natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation.

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

SB 32 (2016) requires that CARB ensure a 40% reduction in GHGs by 2030 compared to 1990 levels. The California RPS program that requires utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California. In September 2018, SB 100 was signed into law, which accelerated California’s 50% RPS target to December 31, 2026, increased the RPS target to 60% by December 31, 2030, and further amended the RPS statute to set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045. Additionally, EO B-55-18 set a statewide goal to achieve economy-wide carbon neutrality by 2045 and to maintain net negative emissions thereafter. The Utility will be an active participant in regulatory proceedings to determine how the state will achieve carbon neutrality. For the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2021, including estimated GHG-free and renewable energy percentages, see “Electric Utility Operations-Electricity Resources” below.

Climate Change Resilience Strategies

During 2021, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to take actions to increase its resilience to the physical impacts of climate change on the Utility’s operations. The Utility regularly reviews the most relevant scientific literature on climate change such as rising sea levels, major storm events, increasing temperatures and heatwaves, wildfires, drought and land subsidence, to help the Utility identify and evaluate climate change-related risks and develop resilience strategies. The Utility maintains emergency response plans and procedures to address a range of near-term risks, including wildfires, extreme storms, and heat waves and considers climate hazards in its risk-assessment process to account for long-term risks associated with climate change. The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.

The Utility is continuing its work to better understand the current and future impacts of climate change. Climate change is incorporated into the Utility’s Risk Assessment Mitigation Phase (“RAMP”) filing, which describes its quantitative risk modeling process and major risks. The Utility also considers the RAMP analysis in developing its infrastructure investment plans. Additionally, the Utility is conducting a system-wide CVA focused on 2050 to identify and help prioritize the Utility’s climate-driven hazards. Concurrent with the CVA are efforts to align key processes with the best available climate projections. For example, the Utility is currently reviewing and updating equipment design standards that rely on historically observed heat thresholds, which are not expected to be predictive of future temperatures.
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With respect to electric operations, climate scientists project that climate change will lead to increased electricity demand due to more extreme and frequent hot weather. The Utility believes its strategies to reduce GHG emissions through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage will help it adapt to the expected changes in demand for electricity. The Utility is making substantial investments to build a more resilient system that can better withstand extreme weather and related emergencies. For more information on such investments, see “Performance: Underpinning The Triple Bottom Line” above. Over the long term, the Utility also faces the risk of higher flooding and inundation potential at coastal and low elevation facilities due to projected sea level rise combined with high tides, storm runoff and storm surges. Inland areas, such as near the Sacramento-San Joaquin River Delta, will also be vulnerable to flooding amid changes to precipitation patterns and extreme storms. As the state continues to face increased risk of wildfires, the Utility’s wildfire mitigation activities, including vegetation management and undergrounding electric powerlines, will continue to play an important role to help reduce the risk of wildfire and its impact on electric and gas facilities.

Climate scientists predict that climate change will result in rising temperatures and changes in precipitation patterns in the Utility’s service territory, including decreasing snowpack. This could, in turn, affect the Utility’s hydroelectric generation. This issue is being analyzed as part of the Utility’s CVA. To plan for this change, the Utility is engaging with state and local stakeholders and is also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and collaborating on research and new modeling tools.

With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting.  In addition, the Utility continues to achieve reductions in methane emissions by implementing improvements in leak detection and repair, upgrades at metering and regulating stations, and maintenance and replacement of other pipeline materials. The Utility is also actively engaged with renewable natural gas producers to facilitate supply interconnections with the Utility’s natural gas pipeline system and is participating in CPUC proceedings that evaluate standards to allow for the injection of hydrogen into natural gas systems and decarbonization through electrification.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2020, which is the most recent data available, totaled more than 44 million metric tons of CO2 equivalent, the majority of which came from customer natural gas use. The following table shows the 2020 GHG emissions data the Utility reported to the CARB under AB 32, which is the most recent data available. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Sustainability Report.
Source
Amount (metric tons CO2 equivalent)
Fossil Fuel-Fired Plants (1)
2,550,622 
Natural Gas Compressor Stations and Storage Facilities (2)
315,802 
Distribution Fugitive Natural Gas Emissions 497,512 
Customer Natural Gas Use (3)
40,304,583 
(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.
(2) Includes emissions from compressor stations and storage facilities that are reportable to CARB.
(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the exception of gas delivered to other natural gas local distribution companies.

The Utility utilized the CEC’s Power Source Disclosure program methodology to calculate the CO2 emissions rate associated with the electricity delivered to retail customers in 2020. This resulted in a third-party verified CO2 emissions rate of 160 pounds of CO2 per MWh.

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Air Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Sustainability Report.
20202019
Total NOx Emissions (tons)141 135 
NOx Emissions Rate (pounds/MWh)0.010.01
Total SO2 Emissions (tons)
15 14 
SO2 Emissions Rate (pounds/MWh)
0.001 0.001 

Nuclear Fuel Disposal

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities’ customers. The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay. As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until the DOE fulfills its contractual obligation to take possession of the spent fuel. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel.

In September 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  The claim for the period June 1, 2020 through May 31, 2021, totaled approximately $11.6 million and is currently under review by the DOE.  Amounts reimbursed by DOE are refunded to customers through rates. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

Ratemaking Mechanisms

The Utility’s rates for electric and natural gas utility services are generally set at levels that are intended to allow the Utility to recover its costs of providing service and a return on invested capital (“cost-of-service ratemaking”). In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (e.g., maintenance, administration and general expenses) and capital costs (e.g., depreciation, and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that the Utility is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Item 7. MD&A), including its costs to procure electricity and natural gas for customers and to administer public purpose and customer programs.

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The rate of return on all other Utility assets is set in the CPUC’s cost of capital proceeding. Other than certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume through certain regulatory balancing accounts, or revenue adjustment mechanisms, that are designed to allow the Utility to collect its authorized base revenue requirements regardless of sales volume. As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads.  Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating.

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn some additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.
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See “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC proceedings.

Base Revenues

General Rate Cases

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base. In the past, the CPUC has generally conducted a GRC every three years. Starting with the 2023 GRC, the CPUC will conduct a GRC every four years that includes the Utility’s costs of its gas transmission and storage facilities. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases in revenue requirements for the subsequent years of the GRC period (known as “attrition years”). Attrition year rate adjustments are generally authorized for cost increases related to invested capital and inflation. Parties in the Utility’s GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the overall interests of residential customers, as well as numerous intervenors, that represent other business, community, customer, environmental, and union interests. For more information about the Utility’s GRC, see “Regulatory Matters - 2020 General Rate Case” and “Regulatory Matters - 2023 General 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’s cost of capital proceedings generally take place in a consolidated proceeding with California’s other large investor-owned electric and gas utilities. For more information about the cost of capital proceedings, see “Regulatory Matters - Cost of Capital Proceedings” in Item 7. MD&A.

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. In its TO rate cases, the Utility uses a formula rate methodology, which includes an authorized revenue requirement and rate base for a given year but also provides for an annual update of the following year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate are either collected from or refunded to customers. The FERC-approved formula rate will be effective through December 31, 2023. 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.

Program-Specific Memorandum Account and Balancing Account Costs

Periodically, costs arise outside of the CPUC GRC rate requests or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, new programs, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed reasonable. For instance, these accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. Recovery of the costs tracked in these memorandum accounts in rates requires CPUC authorization in separate proceedings for which the Utility may be unable to predict the outcome. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts. The CPUC may authorize recovery of costs tracked in the balancing accounts on either a “one-way” basis, which only allows actual costs to be recovered up to a pre-established cap, or a “two-way” basis, which allows actual costs to be recovered, subject to CPUC review. For more information, see “Regulatory Matters - Cost Recovery Proceedings” in Item 7. MD&A and Note 4 of the Notes to the Consolidated Financial Statements in Item 8.

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Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California IOUs 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 BPPs based on long-term demand forecasts. In October 2015, the CPUC approved the Utility’s most recent comprehensive BPP. 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 BPPs 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 value of lost generation due to unplanned outages at utility-owned generation facilities.

The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 4 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, net of Portfolio Allocation Balancing Account balances, exceed five percent of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the procurement transactions recovered in various balancing accounts, including the Energy Resource Recovery Account and the Portfolio Allocation Balancing 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 BPP, to meet mandatory renewable energy targets, and to comply with RA requirements. For more information, see “Electric Utility Operations - Electricity Resources” below as well as Note 15 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility is also responsible, as the central procurement entity (“CPE”) for its distribution service area, for seeking to procure the entire amount of required local RA on behalf of all load serving entities in its distribution service area. The decision grants the Utility, acting as CPE, discretion to defer procurement of local resources to the CAISO’s backstop mechanisms if bid costs are deemed unreasonably high. The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, as long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met. In connection with its CPE function, the Utility is responsible for making compliance demonstrations to the CPUC and the CAISO. The Utility recovers its administrative and procurement costs associated with its CPE function through a balancing account. Each year, the CPUC reviews the Utility’s forecasted administrative costs related to the CPE function and approves a forecasted revenue requirement associated with the administrative costs. The CPUC performs an annual compliance review of the CPE function, including procurement transactions with terms of five years or less (for which costs incurred in compliance with certain prescribed criteria are deemed reasonable and pre-approved without further after-the-fact reasonableness review). Procurement transactions with terms exceeding five years are reviewed separately. The CPUC may disallow costs associated with the CPE function that were not incurred in compliance with the CPUC’s decisions and guidance.

The CPUC has also approved the Power Charge Indifference Adjustment (“PCIA”). The PCIA is a cost recovery mechanism to ensure that customers who switch from the Utility’s bundled service to a non-Utility provider, such as a DA or CCA provider, pay their share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf.

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.

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The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its CPIM described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rate changes.

The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio. Under the CPIM, the Utility’s natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered through rates. One-half of the costs above 102% of the benchmark are recoverable through rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of these savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements are governed by the 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 discounted rates for specified types of customers, such as for low-income customers under the CARE program, which is paid for by the Utility’s other customers.

Nuclear Decommissioning Costs

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. Nuclear decommissioning costs are generally collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. The Utility files an application with the CPUC every three years requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear plants. If the nuclear decommissioning trusts are overfunded, the amount of such overfunding will be returned to customers. Pursuant to Public Utilities Code Section 8325, to the extent the monies available for decommissioning are insufficient to pay for all reasonable and prudent decommissioning costs, the CPUC must authorize the electric utility to collect these charges from its customers.

For costs related to AROs see “Nuclear Decommissioning Obligation” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8.

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Human Capital

Employees and Contractors

As of December 31, 2021, PG&E Corporation and the Utility had approximately 26,000 regular employees, 11 of whom were employees of PG&E Corporation. Of the Utility’s regular employees, approximately 16,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”). The collective bargaining agreements currently in effect for the IBEW Local 1245 and ESC Local 20 will expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits. The IBEW and ESC represent approximately 62% of the Utility’s employee workforce and support several areas of the Utility’s business, including gas and electric operations. The term of the SEIU bargaining agreement ended on December 31, 2021. The parties have reached an agreement which is pending ratification by the SEIU. The Utility enjoys stable and productive relationships with its unions and did not experience any work stoppages in 2021.

PG&E Corporation’s employees are primarily at the executive management level, which experienced significant employee turnover throughout the course of its Chapter 11 Cases in 2019 and 2020. The Utility generally has a stable workforce, which translated into low voluntary turnover during that period. The Utility’s turnover rates for 2021 and 2020 were 5.8% and 4.7%, respectively. Approximately 41% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, with an average tenure of 11 years. Currently, approximately 21% of PG&E Corporation’s and the Utility’s employees are eligible to retire. (PG&E Corporation and the Utility define retirement age as 55 years and older.)

The Utility’s contractors and subcontractors include approximately 35,300 individuals from approximately 1,560 contractor companies.

Human Capital Management

PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce. PG&E Corporation’s and the Utility’s Boards of Directors are responsible for overseeing management’s development and execution of PG&E Corporation’s and the Utility’s human capital strategy.

To build employee engagement, the Utility has a variety of both executive-level and employee-led initiatives and programs. PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and values that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity and inclusion, environmental leadership, and community service. The Utility conducts a biennial employee engagement survey, quarterly pulse surveys, and voluntary upward feedback surveys to measure and track employee engagement progress.

Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures. In addition, employees are required to complete an annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities.

Among other programs, the Utility provides career opportunities through its Power Pathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations. PowerPathway helps people throughout the Utility service territory, including women and military veterans, prepare and compete for high demand jobs in the utility and energy industry. Students receive approximately eight weeks of industry-informed curriculum to ensure the academic, job specific, employability skills and physical training necessary to effectively compete for entry-level employment. Programs may also include hands-on training and on-the-job training.

PG&E Corporation and the Utility also provide integrated solutions and programs that cover employee health and wellness and that encompass physical, emotional, and financial health, including an on-site health clinic, an annual health screening, and health management tools and resources, in addition to more traditional programs.

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PG&E Corporation’s and the Utility’s financial incentives offered to employees include a Short-Term Incentive Plan (“STIP”), an at-risk part of employee compensation designed to reward eligible employees for achieving specific performance goals. The 2021 STIP was focused on company objectives of safety, customer impact, and financial health.

All PG&E Corporation or Utility officer compensation currently is funded by shareholders.

Safety

The Utility has developed a five-year workforce safety strategy that includes two major pillars: systems and culture. Systems refers to risk management, equipment, processes and procedures. Culture refers to employee engagement, adherence to established requirements, a sense of urgency for safety, and leadership. Focus areas in the Utility’s workplace safety strategy include: an enterprise safety management system, enhanced risk management, strengthening the contractor management program, improvement of safety technical standards, ergonomics, safety audits, improving data management and reporting systems, and enhancing safety leadership training. For employees and contractors performing medium- and high-risk work, the Utility’s safety metrics include the number of SIF-A incidents and the SIF-P rate, which measures events that could have resulted in a SIF-A per 200,000 hours worked. In 2021, the Utility had five SIF-A events, which resulted in three fatalities and three serious injuries, and a SIF-P rate of 0.11, which was 10% higher than the SIF-P rate in 2020. The requirement for contractors to report SIF-P events was implemented in June 2020. Additionally, the Utility measures DART. In 2021, the Utility’s DART was 1.01, which was 25% lower than in 2020 and its lowest rate in the past five years.

Throughout the COVID-19 pandemic, PG&E Corporation and the Utility have continued to monitor activities at the Centers for Disease Control and Prevention and the World Health Organization, PG&E Corporation and the Utility have updated their protocols and actions in accordance with guidance from these organizations, following state and local health and safety regulations, and in consultation with the Utility’s medical director. PG&E Corporation and the Utility have also remained focused on protecting the health and safety of their employees, contractors and the Utility’s customers, while continuing to perform critical utility work, and have continued to monitor and track the impact of the pandemic, modifying or adopting new policies in support of their employees’ health and safety as pandemic conditions and governmental response have changed. For example, PG&E Corporation and the Utility have directed employees to work remotely from home where possible, implemented face coverings, physical distancing policies, and required a daily health check when an employee works outside his or her home, required virtual ergonomic evaluations to ensure that employees working from home so do safely and ergonomically, provided additional COVID-19 safety resources for employees who perform utility work in the field, and updated several of their employee benefits as a result of COVID-19, including healthcare benefits and interim time off and leave policies that support the care and new educational environment of children during the pandemic.

Diversity and Inclusion

PG&E Corporation’s and the Utility’s goal is to foster a diverse, equitable, and inclusive environment that enables all of their coworkers to bring their best selves to work so that they can provide exceptional customer service. These efforts are led by PG&E Corporation’s and the Utility’s Executive Vice President, People, Shared Services and Supply Chain, with support from the executive team. The People and Compensation Committee of PG&E Corporation’s Board of Directors reviews the companies’ diversity and inclusion practices and performance.

Key elements of PG&E Corporation’s and the Utility’s approach include active programming to heighten cultural competency, encourage understanding and appreciation of diversity, and integrate thoughtful content into training and performance support materials.

Additionally, the Utility’s 11 Employee Resource Groups and three Engineering Network Groups execute enterprise-wide programming, certain coworkers lead efforts within their departments, and other specialized teams facilitate dialogue across the companies. These efforts foster employee belonging and support an environment of inclusion that values and respects diversity in the workforce.

In 2021, women, minorities, and military veterans accounted for approximately 27%, 48% and 7%, respectively, of total PG&E Corporation and Utility employees. Approximately 8% of the Utility’s employees are younger than 30, 60% are between the ages of 30 and 49, and 32% are 50 or older.

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Electric Utility Operations

The Utility generates electricity and provides electric transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides “bundled” services (i.e., electricity, transmission, and distribution services) to customers in its service territory. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations. For more information, see “Regulatory Matters” in Item 7. MD&A.

Electricity Resources

The Utility is required to maintain capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand.

The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2021 represented by each major electric resource, and further discussed below. The Utility’s deliveries were primarily from renewable energy resources that qualify under California’s RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California’s RPS requirements and SB 100 goal to serve 100% of retail electricity sales with GHG-free resources by 2045 are discussed further below and in the Environmental Regulation section above.

The total estimated electricity generated, procured, and sold (net), as of December 31, 2021 was 33,149 GWh (1) and comprised of the following:
Percent of Bundled Retail Sales (estimated procurement)
CEC Reporting Methodology Adjustment(2)
Percent of Bundled Retail Sales (estimated Power Content Label) (2)
Owned Generation Facilities
Renewable (3)
%— %%
Nuclear39 %— %39 %
Large Hydroelectric%— %%
Fossil fuel-fired (4)
19 %(15)%%
  Total64 %(15)%49 %
Third-Party Purchase Agreements
Renewable (3)
48 %— %48 %
Large Hydroelectric— %— %— %
Fossil fuel-fired (4)
15 %(12)%%
Total63 %(12)%51 %
Others, Net (2)(5)
(27)%27 % %
TOTAL100 % %100 %
Total Renewable Energy Resources (3)
50 % %50 %
GHG-Free Resources (6)
93 % %93 %
(1) This amount excludes electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.
(2) The allocation of “Others, Net” in the “CEC Reporting Methodology Reduction” and “Power Content Label” columns is consistent with CEC guidelines, applied to specified electric generation and procurement volumes (i.e., fossil fuel-fired, nuclear, large hydroelectric, and renewable). Total reported generation and procurement volumes equate to actual electric retail sales.
(3) Amounts include biopower (e.g., biogas, biomass), solar, wind, certain hydroelectric (i.e., 30MW or less), and geothermal facilities.
(4) Amounts consist primarily of natural gas facilities.
(5) Amount is mainly comprised of net CAISO open market (sales)/purchases.
(6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold.

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Renewable Energy Resources

California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. SB 350 increased the amount of renewable energy that must be delivered by most LSEs, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period, to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period, and in each three-year compliance period thereafter, unless changed by legislative action. SB 350 provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.

Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated as 50% in 2021.

The estimated total renewable deliveries as of December 31, 2021 shown above was 16,387 GWh and comprised of the following:
Type
Percent of Bundled Retail Sales (estimated procurement)(1) (2)
Biopower%
Geothermal%
RPS-Eligible Small Hydroelectric%
Solar28 %
Wind11 %
Total50 %
(1) Estimated renewable procurement amounts are expected to be consistent with Power Content Label reporting and adjustments, based on current CEC guidelines.
(2) Estimated renewable procurement percentages above and renewable compliance percentages are expected to be consistent; however, final RPS compliance reporting may result in some differences between the two percentages.

Energy Storage

Energy storage improves system reliability and supports California’s decarbonization goals by integrating increased levels of renewable energy. The CPUC has established a multi-year energy storage procurement framework, under which the Utility was required to procure 580 MW of qualifying storage capacity by the end of 2020, with all energy storage projects required to be operational by the end of 2024. As of December 31, 2021, the Utility was on track to meet its storage goals by the end of 2024.

Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023. In January 2022, the Utility also requested CPUC approval for another 1,600 MW of storage to be completed by the summer of 2024, which would bring the Utility’s total energy storage system capacity to more than 3,330 MW. Finally, the Utility expects to solicit 200 MW of long-duration storage, which is storage with at least eight hours of discharge capacity, in 2022 to have these resources online between 2026 and 2028.

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Owned Generation Facilities

At December 31, 2021, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:
Generation TypeCounty LocationNumber of UnitsNet Operating Capacity (MW)
Nuclear (1):
  Diablo CanyonSan Luis Obispo2,240 
Hydroelectric (2):
  Conventional16 counties in northern and central California100 2,648 
  Helms pumped storageFresno1,212 
Fossil fuel-fired:
  Colusa Generating StationColusa657 
  Gateway Generating Station Contra Costa580 
  Humboldt Bay Generating StationHumboldt10 163 
Photovoltaic (3):
Various13 152 
Total130 7,652 
(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.
(2) The Utility’s hydroelectric system consists of 103 generating units at 64 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for two small powerhouses not subject to the FERC’s licensing requirements), with license terms between 30 and 50 years.
(3) The Utility’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 15 of the Notes to the Consolidated Financial Statements in Item 8.

Electricity Transmission

At December 31, 2021, the Utility owned approximately 18,000 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 33 electric transmission substations with a capacity of approximately 70,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO.

Electricity Distribution

The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2021, approximately 25% are underground and approximately 75% are overhead), 67 transmission switching substations, and 753 distribution substations with a capacity of approximately 35,000 MVA. The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.

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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.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2019 to 2021 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 2021, 2020 or 2019.
202120202019
Customers (average for the year)5,539,969 5,498,044 5,457,101 
Deliveries (in GWh) (1) 
78,588 78,497 78,070 
Revenues (in millions):
   Residential$6,089 $5,523 $4,847 
   Commercial5,042 4,722 4,756 
   Industrial1,493 1,530 1,493 
   Agricultural1,565 1,471 1,106 
   Public street and highway lighting73 69 67 
   Other (2)
(84)(130)168 
      Subtotal14,178 13,185 12,437 
Regulatory balancing accounts (3)
953 673 303 
Total operating revenues$15,131 $13,858 $12,740 
Selected Statistics:
Average annual residential usage (kWh)5,889 6,179 5,750 
Average billed revenues per kWh:
Residential$0.2125 $0.1852 $0.1762 
Commercial0.1802 0.1730 0.1585 
Industrial0.1075 0.1085 0.1015 
Agricultural0.2104 0.2210 0.2172 
Net plant investment per customer$9,199 $8,889 $8,375 
(1) These amounts include electricity provided by DA providers and CCAs that procure their own supplies of electricity for their respective customers.
(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 96% of core customers, representing approximately 85% of the annual core market demand, receive bundled natural gas service from the Utility.

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The Utility generally does not provide procurement service to non-core customers, which must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility with which the Utility has a power purchase agreement 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 2021, the Utility purchased approximately 302,000 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 43% of the total natural gas volume the Utility purchased during 2021.

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, 2021, the Utility’s natural gas system consisted of approximately 43,800 miles of distribution pipelines, over 6,200 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 a firm transportation agreement with Transwestern Pipeline Company, LLC 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. (For more information regarding the Utility’s natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)

The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s gas tr