SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|(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, 2020
|☐||TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
|For the transition period from _________ to ___________ |
Exact Name of Registrant
as Specified In Its Charter
|State or Other Jurisdiction of|
Incorporation or Organization
|1-2348||PACIFIC GAS AND ELECTRIC COMPANY||California||94-0742640|
|77 Beale Street||77 Beale Street|
|P.O. Box 770000||P.O. Box 770000|
|San Francisco,||California||94117||San Francisco,||California||94117|
|(Address of principal executive offices) (Zip Code)||(Address of principal executive offices) (Zip Code)|
|(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 class||Trading Symbol(s)||Name of each exchange on which registered|
|Common stock, no par value||PCG||The New York Stock Exchange|
|Equity Units||PCGU||The New York Stock Exchange|
|First preferred stock, cumulative, par value $25 per share, 5% series A redeemable||PCG-PE||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 5% redeemable||PCG-PD||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 4.80% redeemable||PCG-PG||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 4.50% redeemable||PCG-PH||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable||PCG-PI||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 6% nonredeemable||PCG-PA||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable||PCG-PB||NYSE American LLC|
|First preferred stock, cumulative, par value $25 per share, 5% nonredeemable||PCG-PC||NYSE 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:|
|Pacific Gas and Electric Company:||☐||Yes||☒||No|
|Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:|
|Pacific Gas and Electric Company:||☐||Yes||☒||No|
|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. |
|Pacific Gas and Electric Company:||☒||Yes||☐||No|
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).
|Pacific Gas and Electric Company:||☒||Yes||☐||No|
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 Corporation||Pacific Gas and Electric Company|
|☒||Large accelerated filer||☐||Large accelerated filer|
|Non-accelerated filer||☒||Non-accelerated filer|
|☐||Smaller reporting company||☐||Smaller reporting company|
|☐||Accelerated filer||☐||Accelerated filer|
|☐||Emerging growth company||☐||Emerging 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.|
|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.
|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).|
|Pacific Gas and Electric Company:||☐||Yes||☒||No|
|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.|
|Pacific Gas and Electric Company:||☒||Yes||☐||No|
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2020, the last business day of the most recently completed second fiscal quarter:
|PG&E Corporation common stock|
|Pacific Gas and Electric Company common stock|| Wholly owned by PG&E Corporation|
Common Stock outstanding as of February 22, 2021:
|Pacific Gas and Electric Company:||264,374,809||shares (wholly owned by PG&E Corporation)|
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 Shareholders||Part III (Items 10, 11, 12, 13 and 14)|
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|
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
|2020 Form 10-K||PG&E Corporation’s and Pacific Gas and Electric Company’s combined Annual Report on |
Form 10-K for the year ended December 31, 2020
|ABR||alternate base rate|
|AFUDC||Allowance for Funds Used During Construction|
|ALJ||administrative law judge|
|ARO||asset retirement obligation|
|ASU||accounting standard update issued by the FASB (see below)|
|Backstop Party||a third-party investor party to a Backstop Commitment Letter|
|Bankruptcy Code||the United States Bankruptcy Code|
|Bankruptcy Court||the U.S. Bankruptcy Court for the Northern District of California|
|BPP||bundled procurement plan|
|CAISO||California Independent System Operator|
|Cal Fire||California Department of Forestry and Fire Protection|
|CARB||California Air Resources Board|
|CARE||California Alternate Rates for Energy Program|
|CCA||Community Choice Aggregator|
|CCPA||California Consumer Privacy Act of 2018|
|CEC||California Energy Resources Conservation and Development Commission|
|CEMA||Catastrophic Event Memorandum Account|
|Chapter 11||chapter 11 of title 11 of the U.S. Code|
|Chapter 11 Cases||the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019|
|Confirmation Order||the order confirming PG&E Corporation’s and the Utility’s and the Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization, dated as of June 20, 2020 with the Bankruptcy Court|
|CHT||Customer Harm Threshold|
|CPE||central procurement entities|
|CPIM||Core Procurement Incentive Mechanism|
|CPPMA||COVID-19 Pandemic Protections Memorandum Account|
|CPUC||California Public Utilities Commission|
|CRRs||congestion revenue rights|
|CUE||Coalition of California Utility Employees|
|CVA||Climate Vulnerability Assessment|
|DER||distributed energy resources|
|Diablo Canyon||Diablo Canyon nuclear power plant|
|DIP Credit Agreement||Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPM., as administrative agent, and Citibank, N.A., as collateral agent|
|DOE||U.S. Department of Energy|
|DTSC||Department of Toxic Substances Control|
July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
|EMANI||European Mutual Association for Nuclear Insurance|
|EPA||U.S. Environmental Protection Agency|
|EPS||earnings per common share|
|ERRA||Energy Resource Recovery Account|
|FASB||Financial Accounting Standards Board|
|FEMA||Federal Emergency Management Agency|
|FERC||Federal Energy Regulatory Commission|
|FHPMA||Fire Hazard Prevention Memorandum Account|
|Fire Victim Trust||The trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be funded|
|Forward Stock Purchase Agreements||The prepaid forward contracts between PG&E Corporation and the Backstop Parties dated as of June 19, 2020|
|FRMMA||Fire Risk Mitigation Memorandum Account|
|GAAP||U.S. Generally Accepted Accounting Principles|
|GRC||general rate case|
|GT&S||gas transmission and storage|
|HSM||hazardous substance memorandum account|
|Investment Agreement||The agreement between PG&E Corporation and the PIPE investors dated as of June 7, 2020 relating to the issuance and sale to the PIPE Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock|
|JPM||JPMorgan Chase Bank, N.A.|
|Knighthead||certain funds and accounts managed by Knighthead Capital Management, LLC|
|Lakeside Building||300 Lakeside Drive, Oakland, California, 94612|
|LCC||Land Conservation Commitment|
|LIBOR||London Interbank Offered Rate|
|LSE||load serving entities|
|LSTC||liabilities subject to compromise|
PG&E Corporation 2014 Long-Term Incentive Plan
|MD&A||Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K|
|MGP||manufactured gas plants|
|the Monitor||third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction|
|NAV||net asset value|
|NDCTP||Nuclear Decommissioning Cost Triennial Proceedings|
|NEIL||Nuclear Electric Insurance Limited|
|NEM||net energy metering|
|Noteholder RSA||Restructuring Support Agreement dated as of January 22, 2020 with certain holders of indebtedness of the Utility, among others|
|NRC||Nuclear Regulatory Commission|
|NTSB||National Transportation Safety Board|
|OES||State of California Office of Emergency Services|
|OII||order instituting investigation|
|OIR||order instituting rulemaking|
|OSA||Office of the Safety Advocate, a division of the CPUC|
|PAO||Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)|
|PCAOB||Public Company Accounting Oversight Board (United States) |
|PCIA||Power Charge Indifference Adjustment|
|PERA||Public Employees Retirement Association|
|Petition Date||January 29, 2019|
|PIPE Investor||a third-party investor party to the Investment Agreement|
|Plan||PG&E Corporation and the Utility and the Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization, dated as of June 19, 2020|
|POD||Presiding Officer’s Decision|
|PSA||plan support agreement|
|PSPS||Public Safety Power Shutoff|
|RAMP||Risk Assessment Mitigation Phase|
|ROE||return on equity|
|ROU asset||right-of-use asset|
|RPS||Renewables Portfolio Standard|
|RSA||restructuring support agreement|
|RTBA||Risk Transfer Balancing Account|
|SEC||U.S. Securities and Exchange Commission|
|SED||Safety and Enforcement Division of the CPUC|
|Shareholder Proponents||Knighthead together with Abrams Capital Management, LP|
|SFGO||The Utility’s San Francisco General Office headquarters complex|
Safety Policy Division of the CPUC
PG&E AR Facility, LLC
|Subrogation RSA||Restructuring Support Agreement dated September 22, 2019 with certain holders of insurance subrogation claims, as amended|
|Tax Act||Tax Cuts and Jobs Act of 2017|
|TCC||Official Committee of Tort Claimants|
|TCC RSA||Restructuring 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|
|TURN||The Utility Reform Network|
|Utility||Pacific Gas and Electric Company|
|VIE(s)||variable interest entity(ies)|
|VMBA||Vegetation Management Balancing Account|
|WEMA||Wildfire Expense Memorandum Account|
|Wildfire Fund||statewide fund established by AB 1054 that will be available for eligible electric utility|
companies to pay eligible claims for liabilities arising from wildfires occurring after July 12,
2019 that are caused by the applicable electric utility company’s equipment
|Wildfires OII||Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire|
|WMBA||Wildfire Mitigation Balancing Account|
|WMCE||Wildfire Mitigation and Catastrophic Events|
|WMP||wildfire mitigation plan|
|WMPMA||Wildfire Mitigation Plan Memorandum Account|
|WSD||Wildfire Safety Division|
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; estimates and assumptions used in critical accounting policies, including those relating to insurance receivable, 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:
•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 recently undergone by PG&E Corporation and the Utility in connection with their emergence from Chapter 11;
•the ability of PG&E Corporation and the Utility to raise financing for operations and investment;
•the risks and uncertainties associated with appeals of the Confirmation Order;
•the risks and uncertainties associated with the 2019 Kincade fire, including the extent of the Utility’s liability in connection with the 2019 Kincade fire and whether the Utility will be able to timely recover related costs incurred therewith in excess of insurance; the timing of the insurance recoveries; the timing and outcome of the referral of the Cal Fire report in connection therewith to the Sonoma County District Attorney; and 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;
•the risks and uncertainties associated with any other wildfires, including the extent of the Utility’s liability in connection with the 2020 Zogg fire, and the timing of the insurance recoveries; and with any other wildfires that have occurred and/or may occur in the Utility’s service territory for which the cause has yet to be determined;
•the Utility Community Wildfire Safety Program’s ability to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather, including the Utility’s ability to comply with the targets and metrics set forth in its WMP; whether the Utility is able to retain or contract for the workforce necessary to execute its Community Wildfire Safety Program; and the cost of the program and the timing of the outcome of any proceeding to recover such costs through rates;
•the ability of PG&E Corporation and the Utility to securitize $7.5 billion of costs related to the 2017 Northern California wildfires in a financing transaction that is designed to be rate neutral to customers;
•the impact of the Utility’s implementation of its PSPS program, including the timing and outcome of the OII to Examine the Late 2019 Public Safety Power Shutoff Events and Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events and the purported Public Safety Power Shutoff class action filed in December 2019, and whether any fines or 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;
•whether the Utility may be liable for future wildfires, and the impact of AB 1054 on potential losses in connection with such wildfires, including the CPUC’s implementation of the procedures for recovering such losses;
•the risks and uncertainties associated with the requirement under AB 1054 that the Utility maintain a valid safety certification pursuant to Section 8389(e) of the California Public Utilities Code and the potential implications for accessing the Wildfire Fund and in related CPUC proceedings in the event the Utility fails to maintain a valid safety certification, which could also result in the appointment by the CPUC of an independent third-party monitor to oversee the Utility’s operations as part of the Enhanced Oversight and Enforcement Process;
•the risks and uncertainties associated with the Utility’s ability to access the Wildfire Fund, including that the Wildfire Fund has sufficient remaining funds;
•the risks and uncertainties associated with 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, in connection with 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. 18-035509, which has been enjoined as to PG&E Corporation and the Utility pursuant to the Plan with such claims to be resolved by the Bankruptcy Court as part of the claims reconciliation process in the Chapter 11 Cases;
•the timing and outcome of future regulatory and legislative developments, including future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility or its industry;
•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 invoices, the ability of the Utility to mitigate these effects, including with spending reductions, and the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions;
•whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery;
•whether the Utility can obtain wildfire insurance at a reasonable cost in the future, or at all, and whether insurance coverage is adequate for future losses or claims;
•increased employee attrition as a result of the challenging political and operating environment facing PG&E Corporation and the Utility;
•the timing and outcomes of the FERC TO18 and TO19 rate cases, 2018 and 2019 CEMA applications, WEMA application, WMCE application, future applications for cost recovery of amounts recorded to the FRMMA, CPPMA, WMPMA, VMBA, WMBA, and RTBA, future cost of capital proceedings, and other ratemaking and regulatory proceedings;
•the outcome of the probation and the Monitorship imposed by the federal court after the Utility’s conviction in the federal criminal trial in 2017, the timing and outcomes of the debarment proceeding, potential reliability penalties or sanctions from the North American Electric Reliability Corporation, or Western Electricity Coordinating Council, investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes including the costs of complying with any additional conditions of probation imposed in connection with the Utility’s federal criminal proceeding, such as expenses associated with any material expansion of the Utility’s vegetation management program, as well as the impact of additional conditions of probation on PG&E Corporation’s and the Utility’s ability to make distributions to shareholders;
•the effects on PG&E Corporation’s and the Utility’s reputations caused by matters such as the CPUC’s investigations and enforcement proceedings and the Utility’s criminal guilty plea as described in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. under the heading “District Attorneys’ Offices Investigations”;
•the outcome of future legislative or regulatory actions as part of the “Enhanced Oversight and Enforcement Process” or otherwise that may be taken, such as requiring the Utility to transfer ownership of the Utility’s assets to municipalities or other public entities, or implement corporate governance, operational or other changes;
•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 project 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;
•whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and information technology systems from cyber- and physical attacks, or other internal or external hazards;
•the timing and outcome in the Court of Appeals of 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 outcome of current and future self-reports, investigations, or other enforcement proceedings that could be commenced or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including 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, environmental laws and regulations; and the outcome of existing and future SED notices of violations;
•the impact of government regulations that the Utility is subject to, including environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover such compliance costs in rates or from other sources;
•the impact of SB 100, signed into law on September 10, 2018, which increased the percentage from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and establishes state policy that 100% of all retail electricity sales must come from renewable portfolio standard-eligible or carbon-free resources by 2045;
•how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, distributed energy resources, electric vehicles, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;
•the impact of the California governor’s executive order issued on January 26, 2018, to implement a new target of five million zero-emission vehicles on the road in California by 2030 and the California governor’s executive order issued on September 23, 2020, requiring sales of all new passenger vehicles to be zero-emission by 2035 and additional measures to eliminate harmful emissions from the transportation sector;
•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 of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of potential actions, such as legislation, taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon until its planned retirement;
•the impact of wildfires, droughts, floods, high winds, lightning or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, 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 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 subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;
•the breakdown or failure of equipment that can cause damages, including fires, and unplanned outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;
•the outcome of future legislative developments in connection with SB 350 (the Golden State Energy Act), a bill which was signed into law on June 30, 2020 and authorizes the creation by the California governor of a new entity “Golden State Energy,” a nonprofit public benefit corporation, for the purpose of acquiring the Utility’s assets and serving electric and gas in the Utility’s service territory in the event that the CPUC revokes the Utility’s Certificate of Public Convenience and Necessity;
•whether the Utility’s climate change adaptation strategies are successful;
•the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs and DA providers, have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, 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 amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;
•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, the PIPE Investors and the Backstop Parties;
•the impact of the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the uncertainty in connection with the Utility’s probation or enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation;
•the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation;
•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), as a result of which tax attributes could be limited;
•changes in the regulatory and economic environment, including potential changes affecting clean energy and tax policy, as a result of the current federal administration and Congress; 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.
PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “PG&E Progress,” “Chapter 11,” “Wildfire and Safety Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. 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.
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. 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 2020 Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors and the section entitled “Forward-Looking Statements” above.
The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is subject to the jurisdiction of 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.
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” under Item 7. MD&A.)
PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
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, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED has the discretion either to address each violation in a distinct citation or to include multiple violations in a single citation regardless of whether the violations occurred in the same incident or are of a similar nature. 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 California State Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to wildfires and wildfire cost recovery, increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, the establishment of energy storage procurement targets, and the development of a state-wide electric vehicle charging infrastructure. The CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. The CPUC also conducts audits and reviews of the Utility’s accounting, performance, and compliance with regulatory guidelines.
The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. (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.)
Federal Energy Regulatory Commission and California Independent System Operator
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.)
The California Energy Commission is the state’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 California Air Resources Board 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 National Transportation Safety Board is an independent U.S. government investigative agency responsible for civil transportation accident investigations, including pipeline accidents. The NTSB also conducts special investigations and safety studies, and issues safety recommendations to prevent future accidents. As a result of its investigation into the September 2010 San Bruno natural gas explosion, the NTSB issued 12 safety recommendations to the Utility, and also subsequently issued 28 safety recommendations for the gas pipeline industry as a result of a safety study on integrity management of gas transmission pipelines in urban areas.
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 and/or use public property for the operation of the Utility’s business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric 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.)
On April 12, 2017, the Utility retained a third-party monitor (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, with the ability to apply for early termination after three years. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations and maintains effective ethics, compliance, and safety related incentive programs on a Utility-wide basis. (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.)
Material Effects of Compliance with Material 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 capital expenditures and has had in the past and may continue to have in the future a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, cash flows and competitive position. Generally, the Utility expects to recover the cost of compliance with government regulations from customers through its GRC proceedings, or other proceedings. To the extent the Utility incurs costs above authorized or incurs additional types of costs not included in rates, the Utility would expect to apply for recovery of such costs. Such recovery would be subject to the CPUC’s approval and could involve its reasonableness review.
Costs incurred in 2020 included costs associated with upgrading and maintaining the Utility’s electric and natural gas infrastructure in accordance with CPUC requirements and NTSB safety recommendations, costs in connection with participating in the Wildfire Fund under AB 1054, costs in connection with execution of wildfire mitigation efforts, the cost of complying with the licensing regulations of the FERC, and expenses under 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 and “Regulatory Matters” in Item 7. MD&A.)
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 in 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 U.S. Environmental Protection Agency (EPA), including the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended. The Utility is also subject to the regulations adopted by other federal agencies responsible for implementing federal environmental laws. The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies. These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors. Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, monitoring and paying for the harm caused to natural resources, and paying for the costs of health studies.
The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former manufactured gas plant 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.
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.
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 Executive Order 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, following the D.C. Circuit’s decision to vacate and remand the Trump Administration’s Affordable Clean Energy rule on January 19, 2021.
California’s AB 32, the Global Warming Solutions Act of 2006, provides 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 the state’s 50% RPS target to December 31, 2026, increased the RPS target to 60% by December 31, 2030, and further amended the RPS statute to set a policy of meeting 100% of retail sales from eligible renewables and zero-carbon resources by December 31, 2045. Additionally, Executive Order B-55-18 set a statewide goal to achieve economy-wide carbon neutrality by 2045 and to maintain net negative emissions thereafter. The Utility will be an active participant in regulatory proceedings to determine how the state will achieve carbon neutrality.
Climate Change Resilience Strategies
During 2020, 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 in light of the 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 the necessary 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 uses its risk-assessment process to prioritize infrastructure investments for longer-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 working to better understand the current and future impacts of climate change. The Utility’s safety risks are included in its RAMP submittals with the CPUC. The Climate Resilience RAMP model indicated potential additional Utility safety consequences due to climate change, including in the near term. The Utility is conducting foundational work to help anticipate and plan for evolving conditions in terms of weather and climate-change related events. This work is guiding efforts to design a Utility-wide climate change risk integration strategy. This strategy will inform resource planning and investment, operational decisions, and potential additional programs to identify and pursue mitigations that will incorporate the resilience and safety of the Utility’s assets, infrastructure, operations, employees, and customers. The strategy will be informed by a multi-year, system-wide CVA to better understand how climate-driven natural hazards will impact the Utility’s assets, services, and operations.
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 are strategies that 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. 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 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 activities, including vegetation management, 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.
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 2019, which is the most recent data available, totaled about 46 million metric tonnes of CO2 equivalent, the majority of which came from customer natural gas use. The following table shows the 2019 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 Responsibility and Sustainability Report.
Amount (metric tonnes CO2 equivalent)
Fossil Fuel-Fired Plants (1)
Natural Gas Compressor Stations and Storage Facilities (2)
|Distribution Fugitive Natural Gas Emissions ||496,789 |
Customer Natural Gas Use (3)
(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 2019. As required by AB 1110, the CEC modified the Power Source Disclosure program methodology in 2020 for the 2019 reporting year. This modified methodology differed from prior reporting years and resulted in a third-party verified CO2 emissions rate for 2019 that was virtually GHG emissions free.
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 Responsibility and Sustainability Report.
|Total NOx Emissions (tons)||135 ||134 |
|NOx Emissions Rate (pounds/MWh)||0.01||0.01|
Total SO2 Emissions (tons)
|14 ||15 |
SO2 Emissions Rate (pounds/MWh)
|0.001 ||0.001 |
In 2014, the EPA issued final regulations to implement the requirements of the federal Clean Water Act that require cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts. Various industry and environmental groups challenged the federal regulations and they were upheld by the U.S. Court of Appeals for the Second Circuit. California’s once-through cooling policy adopted by the California Water Board in 2010 is considered to be at least as stringent as the new federal regulations and therefore governs implementation in California.
The California Water Board’s policy generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. The policy also provided for an alternative compliance approach for nuclear plants if certain criteria were met. As required by the policy, the California Water Board appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at Diablo Canyon. The committee’s consultant submitted its final report to the California Water Board in September 2014. The report addressed feasibility, costs and timeframes to install alternative technologies at Diablo Canyon, such as cooling towers.
On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon’s two nuclear power reactor units at the expiration of their current operating licenses in 2024 and 2025. The CPUC approved the retirement in January 2018. As a result of the planned retirement, the California Water Board will no longer need to address alternative compliance measures for Diablo Canyon. As required under the policy, the Utility will continue to pay an annual interim mitigation fee until operations cease in 2025.
Additionally, in December 2020, the Utility reached a settlement with the Central Coast Regional Water Quality Control Board and the California Attorney General’s Office regarding the thermal component of the plant’s once-through cooling discharge. Under the settlement, which will take the form of a Consent Judgement filed in San Luis Obispo County Superior Court, the Utility will make a payment of $5.9 million, funding local water quality projects selected by the Central Coast Board.
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (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, 2019 through May 31, 2020, totaled approximately $8.5 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.
The Utility’s rates for electric and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service and a return on invested capital (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC conduct proceedings to determine the 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, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.
The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. 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 fully collect its authorized base revenue requirements. 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 generally increase during the winter months (November to March) to account for the gas peak 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.
See “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC proceedings.
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, including return on rate base, related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations. The CPUC generally conducts a GRC every three or four years. Starting with the 2023 GRC, the CPUC will conduct a GRC every 4 years. 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 provided for cost increases related to increases in invested capital and inflation. Parties in the Utility’s GRC include the PAO 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.
On January 16, 2020, the CPUC approved a final decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, as a result of which the Utility will combine its GRC and GT&S rate cases starting with the 2023 GRC. (For more information about the Utility’s GRC, see “Regulatory Matters - 2017 General Rate Case” and “Regulatory Matters - 2020 General Rate Case” in Item 7. MD&A.)
Natural Gas Transmission and Storage Rate Cases
The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in the GT&S rate case. The CPUC generally has conducted a GT&S rate case every three or four years. Similar to the GRC, the CPUC approves the annual revenue requirements for the first year (or “test year”) of the GT&S rate case period and typically determines annual increases in revenue requirements for attrition years of the GT&S rate case period. Parties in the Utility’s GT&S rate case include the PAO and TURN.
As previously mentioned, on January 16, 2020, the CPUC approved a final decision that requires the Utility to combine its GRC and GT&S rate cases starting with the 2023 GRC. (For more information, see “Regulatory Matters - 2015 Gas Transmission and Storage Rate Case” and “Regulatory Matters - 2019 Gas Transmission and Storage Rate Case” in Item 7. MD&A.)
Cost of Capital Proceedings
The CPUC periodically conducts a cost of capital proceeding to authorize the Utility’s capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. On December 19, 2019, the CPUC issued a final decision that authorizes the Utility’s capital structure through 2022, consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred stock. The CPUC also set the authorized ROE through 2023 at 10.25% and reset the cost of debt to 5.16%. The CPUC also authorized the continuation of an adjustment mechanism to allow the Utility’s cost of debt and ROE to be adjusted if the utility bond index changes by certain thresholds, which are reviewed annually. On August 20, 2020, the CPUC updated the Utility’s authorized cost of long-term debt from 5.16% to 4.17% as a result of the Chapter 11 exit financing.
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. On December 30, 2020, the FERC approved a final settlement of the Utility’s formula rate. 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.
Memorandum Account Costs
Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC rate requests or that have been deliberately excluded therefrom. These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. While the Utility expects such costs to be recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC for which the Utility may be unable to predict the outcome. (For more information, see “Regulatory Matters - Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account,” “Regulatory Matters - Catastrophic Event Memorandum Accounts and Applications,” and “Regulatory Matters - Wildfire Mitigation Memorandum and Balancing Accounts” in Item 7. MD&A.)
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 cost of replacement power procured 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 exceed five percent of its prior year electric procurement and Utility-owned generation revenues. The CPUC performs an annual compliance review of the transactions recorded in the ERRA.
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 resource adequacy 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.)
Natural Gas Procurement, Storage, and Transportation Costs
The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electric rates.
The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments for its core gas portfolio, through its retail gas rates, subject to limits as set forth in its CPIM described below. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with 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 in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of these savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.
The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements are governed by 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 California Alternate Rates for Energy (“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.
For costs related to Asset Retirement Obligations see “Nuclear Decommissioning Obligation” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
At December 31, 2020, PG&E Corporation and the Utility had approximately 24,000 regular employees, 8 of whom were employees of PG&E Corporation. Of the Utility’s regular employees, approximately 15,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“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 63% 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 ends on December 31, 2021. The Utility intends to initiate general negotiations of the SEIU bargaining agreement in summer of 2021.
PG&E Corporation, on average has approximately 10 employees, all 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. Approximately 42% of PG&E Corporation’s and the Utility’s employees have a tenure of more than 10 years, resulting in an average tenure of 12 years. Currently, approximately 23% 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.)
Human Capital Management
PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained and diverse 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. Among other things, 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.
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. For example, PG&E Corporation and the Utility provide employees a range of technical training 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.
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.
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 goals. The 2020 STIP was focused on company objectives of safety, customer impact, and financial health.
Any PG&E Corporation or Utility officer compensation currently is funded by shareholders.
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, contractor management, improvement of safety technical standards, musculoskeletal disorder programs and ergonomics, safety audits, data management, systems and reporting, and safety culture. The Utility uses a variety of metrics to track workforce safety performance, including the number of injuries that result in days away, restricted or transferred duty per 200,000 hours worked (“DART”). In 2020, the Utility’s DART was 1.34, which was 35% lower than in 2019 and its lowest rate in the past five years.
In addition to employee safety, a key area of the Utility’s workforce safety strategy includes strengthening contractor safety. The Utility’s Contractor Safety Program requires contractors performing medium- and high-risk work to meet prequalification requirements to perform work for or on behalf of the Utility. The Utility’s contractors and subcontractors include approximately 26,000 individuals from approximately 2,200 contractor companies. For employees and contractors performing medium- and high-risk work, the Utility’s safety metrics include the number of workforce serious injuries and fatalities (“SIF-A”) and events that could have resulted in a SIF-A per 200,000 hours worked (the “SIF-P rate”). In 2020, the Utility had 10 SIF-A events, which resulted in five fatalities and seven injuries, and a SIF-P rate of 0.10, which was 29% lower than in 2019. The Utility began including contractors in its SIF-P rate in June 2020.
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, and have updated the Utility’s protocols and actions in accordance with guidance from these organizations and with consultation from 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 new face coverings and physical distancing policies, required virtual ergonomic evaluations to ensure that employees now 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 culture and workforce. These efforts are led by the Utility’s Chief Diversity Officer, with support from the senior leadership team. The Compliance and Public Policy 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 engaging employees, targeted employee development to level the playing field for diverse talent, an ongoing commitment to diversity among our leadership team, and furthering cultural understanding and role-modeling inclusion. In 2020, women, minorities and military veterans accounted for approximately 27%, 46% and 7%, respectively, of total PG&E Corporation and Utility employees.
In addition, the Utility’s 11 Employee Resource Groups and three Engineering Network Groups promote its business objectives and support a culture of diversity and inclusion by fostering employee belonging, supporting an environment of inclusion that values and respects diversity in the workforce, and promoting positive relationships with the communities and customers the Utility serves.
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.)
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 according to which resources are the least expensive.
The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2020 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.
Total 2020 estimated electricity generated, procured, and sold, (net) - 35,838 GWh (1):
|Percent of Bundled Retail Sales (estimated procurement)|
CEC Reporting Methodology Reduction(2)
Percent of Bundled Retail Sales (estimated Power Content Label) (2)
|Owned Generation Facilities|
|1.3 ||%||— ||%||1.3 ||%|
|Nuclear||42.8 ||%||— ||%||42.8 ||%|
|Large Hydroelectric||9.7 ||%||— ||%||9.7 ||%|
Fossil fuel-fired (4)
|17.9 ||%||12.2 ||%||5.7 ||%|
| Total||71.7 ||%||12.2 ||%||59.5 ||%|
|Third-Party Purchase Agreements|
|34.3 ||%||— ||%||34.3 ||%|
|Large Hydroelectric||0.5 ||%||— ||%||0.5 ||%|
Fossil fuel-fired (4)
|18.0 ||%||12.3 ||%||5.7 ||%|
|Total||52.8 ||%||12.3 ||%||40.5 ||%|
Others, Net (2)(5)
|TOTAL||100.0 ||%||— ||%||100.0 ||%|
Total Renewable Energy Resources (3)
|35.6 ||%||— ||%||35.6 ||%|
(1) This amount excludes electricity provided by direct access 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.
Renewable Energy Resources
California law established an RPS that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. In October 2015, the California Governor signed SB 350, the Clean Energy and Pollution Reduction Act of 2015 into law. SB 350 became effective January 1, 2016, and increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period, to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period, and in each three-year compliance period thereafter, unless changed by legislative action. SB 350 provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods. In September 2018, the California Governor signed SB 100 into law, increasing from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and established state policy that 100% of all retail electricity sales must come from RPS-eligible or carbon-free resources by 2045. The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable from customers as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets. The CPUC is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.
Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. RPS requirements are based on procurement, which aligns with the methodology presented in the first column of the table above. Procurement from renewable energy sources was estimated as 35.6% in 2020. In accordance with the Power Content Label methodology presented in the table above, an estimated 35.6% of the Utility’s energy deliveries was from renewable energy sources.
The estimated total 2020 renewable deliveries shown above were comprised of the following:
|Type||GWh||Percent of Bundled Retail Sales (estimated procurement)|
Percent of Bundled Retail Sales (estimated Power Content Label) (1)
|Biopower||1,008 ||2.8 ||%||2.8 ||%|
|Geothermal||920 ||2.6 ||%||2.6 ||%|
|RPS-Eligible Small Hydroelectric||436 ||1.2 ||%||1.2 ||%|
|Solar||5,784 ||16.1 ||%||16.1 ||%|
|Wind||4,617 ||12.9 ||%||12.9 ||%|
|Total||12,765 ||35.6 ||%||35.6 ||%|
(1) Reporting and adjustments based on CEC guidelines.
As required by California law, the CPUC established a multi-year energy storage procurement framework, including energy storage procurement targets to be achieved by each load-serving entity under the CPUC jurisdiction, including the Utility. Under the adopted energy storage procurement framework, the Utility is required to procure 580 MW of qualifying storage capacity by the end of 2021, with all energy storage projects required to be operational by the end of 2024.
The CPUC also adopted biennial interim storage targets for the Utility, beginning in 2014 and ending in 2020. Under the adopted framework, the Utility is required to submit biennial energy storage procurement plans to describe its strategy to meet its interim and total energy storage targets. As of December 31, 2020, the Utility had met its storage targets.
Owned Generation Facilities
At December 31, 2020, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:
|Generation Type||County Location||Number of Units||Net Operating Capacity (MW)|
| Diablo Canyon||San Luis Obispo||2 ||2,240 |
| Conventional||16 counties in northern and central California||100 ||2,655 |
| Helms pumped storage||Fresno||3 ||1,212 |
|Fossil fuel-fired: |
| Colusa Generating Station||Colusa||1 ||657 |
| Gateway Generating Station ||Contra Costa||1 ||580 |
| Humboldt Bay Generating Station||Humboldt||10 ||163 |
| CSU East Bay Fuel Cell||Alameda||1 ||1 |
| SF State Fuel Cell||San Francisco||2 ||2 |
|Various||13 ||152 |
|Total||133 ||7,662 |
(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.
At December 31, 2020, 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 35 electric transmission substations with a capacity of approximately 66,000 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, the Canadian provinces of Alberta and British Columbia, and parts of Mexico.
Decisions about expansions and maintenance of the transmission system can be influenced by decisions of the Utility’s regulators and the CAISO.
The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2020, approximately 25% are underground and approximately 75% are overhead), 68 transmission switching substations, and 758 distribution substations, with a capacity of approximately 32,000 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.
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 2018 to 2020 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 2020, 2019 or 2018.
|Customers (average for the year)||5,498,044 ||5,457,101 ||5,428,318 |
Deliveries (in GWh) (1)
|78,497 ||78,070 ||79,774 |
|Revenues (in millions): |
| Residential||$||5,523 ||$||4,847 ||$||5,051 |
| Commercial||4,722 ||4,756 ||4,908 |
| Industrial||1,530 ||1,493 ||1,532 |
| Agricultural||1,471 ||1,106 ||1,234 |
| Public street and highway lighting||69 ||67 ||72 |
| Subtotal||13,185 ||12,437 ||12,077 |
Regulatory balancing accounts (3)
|673 ||303 ||636 |
|Total operating revenues||$||13,858 ||$||12,740 ||$||12,713 |
|Average annual residential usage (kWh)||6,179 ||5,750 ||5,772 |
|Average billed revenues per kWh: |
|Residential||$||0.1852 ||$||0.1762 ||$||0.1838 |
|Commercial||0.1730 ||0.1585 ||0.1627 |
|Industrial||0.1085 ||0.1015 ||0.1010 |
|Agricultural||0.2210 ||0.2172 ||0.1968 |
|Net plant investment per customer||$||8,889 ||$||8,375 ||$||7,950 |
(1) These amounts include electricity provided by direct access 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 84% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility generally does not provide procurement service to non-core customers, 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 2020, the Utility purchased approximately 282,000 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 17% of the total natural gas volume the Utility purchased during 2020.
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, 2020, the Utility’s natural gas system consisted of approximately 43,500 miles of distribution pipelines, over 6,300 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 transmission system. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later withdrawal. In addition, four independent storage operators are interconnected to the Utility’s northern California transmission system. In 2019, the CPUC approved the discontinuation (through closure or sale) of operations at two gas storage fields.
In 2020, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and continued its work on the final recommendation from the NTSB’s 2010-11 San Bruno investigation to hydrostatically test all high consequence pipeline mileage. The Utility currently plans to complete this NTSB recommendation by 2022 for remaining short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines.
Natural Gas Operating Statistics
The following table shows the Utility’s operating statistics from 2018 through 2020 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2020, 2019 or 2018.