PG&E Corp - Annual Report: 2020 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________
FORM 10-K
| (Mark One) | |||||
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the Fiscal Year Ended December 31, 2020 | |||||
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
| For the transition period from _________ to ___________ | |||||
| Commission File Number | Exact Name of Registrant as Specified In Its Charter | State or Other Jurisdiction of Incorporation or Organization | IRS Employer Identification Number | |||||||||||||||||
| 1-12609 | PG&E CORPORATION | California | 94-3234914 | |||||||||||||||||
| 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) | |||||||||||||||||||||||||
| 415 | 973-1000 | 415 | 973-1000 | |||||||||||||||||||||||
| (Registrant’s telephone number, including area code) | (Registrant’s telephone number, including area code) | |||||||||||||||||||||||||
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||
| Title of each 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: | |||||||||||||||||
| PG&E Corporation: | ☐ | Yes | ☒ | No | |||||||||||||
| 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: | |||||||||||||||||
| PG&E Corporation: | ☐ | Yes | ☒ | No | |||||||||||||
| 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. | |||||||||||||||||
| PG&E Corporation: | ☒ | Yes | ☐ | No | |||||||||||||
| 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). | |||||||||||||||||
| PG&E Corporation: | ☒ | Yes | ☐ | No | |||||||||||||
| 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. | |||||||||||||||||
| PG&E Corporation: | ☐ | ||||||||||||||||
| Pacific Gas and Electric Company: | ☐ | ||||||||||||||||
| Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. | |||||||||||||||||
| PG&E Corporation: | ☒ | ||||||||||||||||
| Pacific Gas and Electric Company: | ☒ | ||||||||||||||||
| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | |||||||||||||||||
| PG&E Corporation: | ☐ | Yes | ☒ | No | |||||||||||||
| 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. | |||||||||||||||||
| PG&E Corporation: | ☒ | Yes | ☐ | No | |||||||||||||
| 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 | $12,130 million | ||||
| Pacific Gas and Electric Company common stock | Wholly owned by PG&E Corporation | ||||
Common Stock outstanding as of February 22, 2021: | ||||||||
| PG&E Corporation: | 1,984,683,820 | shares | ||||||
| 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) | ||||
Contents
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UNITS OF MEASUREMENT
| 1 Kilowatt (kW) | = | One thousand watts | ||||||
| 1 Kilowatt-Hour (kWh) | = | One kilowatt continuously for one hour | ||||||
| 1 Megawatt (MW) | = | One thousand kilowatts | ||||||
| 1 Megawatt-Hour (MWh) | = | One megawatt continuously for one hour | ||||||
| 1 Gigawatt (GW) | = | One million kilowatts | ||||||
| 1 Gigawatt-Hour (GWh) | = | One gigawatt continuously for one hour | ||||||
| 1 Kilovolt (kV) | = | One thousand volts | ||||||
| 1 MVA | = | One megavolt ampere | ||||||
| 1 Mcf | = | One thousand cubic feet | ||||||
| 1 MMcf | = | One million cubic feet | ||||||
| 1 Bcf | = | One billion cubic feet | ||||||
| 1 MDth | = | One thousand decatherms | ||||||
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GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
| 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 | ||||
| AB | Assembly Bill | ||||
| ABR | alternate base rate | ||||
| AFUDC | Allowance for Funds Used During Construction | ||||
| ALJ | administrative law judge | ||||
| AR | accounts receivable | ||||
| 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 | ||||
| DA | Direct Access | ||||
| 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 | ||||
| Effective Date | 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 | ||||
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| EV | electric vehicle | ||||
| 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 | ||||
| GHG | greenhouse gas | ||||
| GRC | general rate case | ||||
| GT&S | gas transmission and storage | ||||
| HSM | hazardous substance memorandum account | ||||
| IOUs | investor-owned utility(ies) | ||||
| 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 | ||||
| LTIP | 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 | ||||
| NBC | Non-Bypassable Charge | ||||
| 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 | ||||
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| PD | proposed decision | ||||
| 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 | ||||
| QF | Qualifying facilities | ||||
| RAMP | Risk Assessment Mitigation Phase | ||||
| RA | Resource Adequacy | ||||
| ROE | return on equity | ||||
| ROU asset | right-of-use asset | ||||
| RPS | Renewables Portfolio Standard | ||||
| RSA | restructuring support agreement | ||||
| RTBA | Risk Transfer Balancing Account | ||||
| SB | Senate Bill | ||||
| 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 | ||||
| SPD | Safety Policy Division of the CPUC | ||||
| SPV | 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 | ||||
| TE | transportation electrification | ||||
| TO | transmission owner | ||||
| 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 | ||||
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FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of capital expenditures; 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;
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•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;
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•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;
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•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.
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PART I
ITEM 1. BUSINESS
PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. 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.
Regulatory Environment
The Utility’s business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is 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.
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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.)
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Other Regulators
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.)
Third-party Monitor
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.)
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Environmental Regulation
The Utility’s operations are subject to extensive federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of activities, including the remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of CO2 and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. (See Item 1A. Risk Factors.) Generally, the Utility recovers most of the costs of complying with environmental laws and regulations 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.
Federal Regulation
At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions.
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Tackling the climate crisis is a key priority of the Biden Administration, and the Administration has signaled its intent to use its executive and regulatory authorities to reduce emissions in line with science-based targets. On January 20, 2021, President Biden issued an 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.
State Regulation
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.
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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.
Emissions Data
PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, the Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 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.
| Source | Amount (metric tonnes CO2 equivalent) | ||||
Fossil Fuel-Fired Plants (1) | 2,484,127 | ||||
Natural Gas Compressor Stations and Storage Facilities (2) | 344,810 | ||||
| Distribution Fugitive Natural Gas Emissions | 496,789 | ||||
Customer Natural Gas Use (3) | 42,058,499 | ||||
(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.
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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.
| 2019 | 2018 | ||||||||||
| 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 | |||||||||
Water Quality
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.
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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.
Ratemaking Mechanisms
The Utility’s rates for electric and natural gas utility services are set at levels that are intended to allow the Utility to recover its 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.
Base Revenues
General Rate Cases
The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, 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.)
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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.
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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.
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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.
Human Capital
Employees
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.
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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.
Safety
The Utility has developed a five-year workforce safety strategy that includes two major pillars: systems and culture. Systems refers to risk management, equipment, processes and procedures. Culture refers to employee engagement, adherence to established requirements, a sense of urgency for safety, and leadership. Focus areas in the Utility’s workplace safety strategy include: an enterprise safety management system, enhanced risk management, 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.
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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.)
Electricity Resources
The Utility is required to maintain capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand 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.
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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 | |||||||||||||||||
Renewable (3) | 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 | |||||||||||||||||
Renewable (3) | 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) | (24.5) | % | (24.5) | % | — | % | |||||||||||
| 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.
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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.
Energy Storage
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) | |||||||||||||||||
Nuclear (1): | ||||||||||||||||||||
| Diablo Canyon | San Luis Obispo | 2 | 2,240 | |||||||||||||||||
Hydroelectric (2): | ||||||||||||||||||||
| 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 | |||||||||||||||||
| Fuel Cell: | ||||||||||||||||||||
| CSU East Bay Fuel Cell | Alameda | 1 | 1 | |||||||||||||||||
| SF State Fuel Cell | San Francisco | 2 | 2 | |||||||||||||||||
Photovoltaic (3): | 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.
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Generation Resources from Third Parties
The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. (See “Ratemaking Mechanisms” above.) For more information regarding the Utility’s power purchase agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
Electricity Transmission
At December 31, 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.
Electricity Distribution
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.
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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.
| 2020 | 2019 | 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 | ||||||||||||||
Other (2) | (130) | 168 | (720) | ||||||||||||||
| Subtotal | 13,185 | 12,437 | 12,077 | ||||||||||||||
Regulatory balancing accounts (3) | 673 | 303 | 636 | ||||||||||||||
| Total operating revenues | $ | 13,858 | $ | 12,740 | $ | 12,713 | |||||||||||
| Selected Statistics: | |||||||||||||||||
| 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.
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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.
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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.
| 2020 | 2019 | 2018 | |||||||||||||||
Customers (average for the year) (1) | 4,545,700 | 4,518,209 | 4,495,279 | ||||||||||||||
| Gas purchased (MMcf) | 226,746 | 227,621 | 219,061 | ||||||||||||||
| Average price of natural gas purchased | $ | 2.02 | $ | 2.08 | $ | 2.02 | |||||||||||
| Bundled gas sales (MMcf): | |||||||||||||||||
| Residential | 162,682 | 162,876 | 156,917 | ||||||||||||||
| Commercial | 49,834 | 54,479 | 51,357 | ||||||||||||||
| Total Bundled Gas Sales | 212,516 | 217,355 | 208,274 | ||||||||||||||
| Revenues (in millions): | |||||||||||||||||
| Bundled gas sales: | |||||||||||||||||
| Residential | $ | 2,517 | $ | 2,325 | $ | 2,042 | |||||||||||
| Commercial | 597 | 605 | 537 | ||||||||||||||
| Other | 61 | 123 | 75 | ||||||||||||||
| Bundled gas revenues | 3,175 | 3,053 | 2,654 | ||||||||||||||
| Transportation service only revenue | 1,211 | 1,249 | 1,151 | ||||||||||||||
| Subtotal | 4,386 | 4,302 | 3,805 | ||||||||||||||
Regulatory balancing accounts (2) | 225 | 87 | 242 | ||||||||||||||
| Total operating revenues | $ | 4,611 | $ | 4,389 | $ | 4,047 | |||||||||||
| Selected Statistics: | |||||||||||||||||
| Average annual residential usage (Mcf) | 37 | 38 | 38 | ||||||||||||||
| Average billed bundled gas sales revenues per Mcf: | |||||||||||||||||
| Residential | $ | 15.09 | $ | 13.88 | $ | 12.67 | |||||||||||
| Commercial | 10.61 | 9.72 | 9.04 | ||||||||||||||
| Net plant investment per customer | $ | 3,794 | $ | 3,522 | $ | 3,417 | |||||||||||
(1) These amounts include natural gas provided by core transport agents and CCAs that procure their own supplies of natural gas for their respective customers.
(2) These amounts represent revenues authorized to be billed.
Competition
Competition in the Electricity Industry
California law allows qualifying non-residential electric customers of IOUs to purchase electricity from energy service providers rather than from the utilities up to certain annual limits specified for each utility. This arrangement is known as “direct access,” or DA. In 2018, the California legislature passed a bill to expand the annual statewide DA cap by 4,000 GWh, and directed the CPUC to consider whether DA should be further expanded, and to present a report on this matter to the legislature by June 30, 2020. In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a CCA to generate and/or purchase electricity for their local residents and businesses. By law, a CCA can procure electricity for all of its residents and businesses that do not affirmatively elect to continue to receive electricity generated or procured by a utility. In 2019, the CPUC issued an order implementing the 4,000 GWh increase for DA transactions, including an apportionment to the Utility’s service area of approximately 1,873 GWh.
On September 28, 2020, the CPUC issued a report recommending that further expansion of DA be conditioned on energy service providers’ demonstrated compliance with the following: (1) Integrated Resource Plan filings and meeting all procurement requirements, (2) RPS obligations for the 2021-2024 compliance period and (3) RA requirements including multi-year local, year-ahead flexible and system, and month-ahead system and flexible obligations. The report also recommends setting an initial re-opening schedule in increments equal to 10% of eligible non-residential load per year beginning no earlier than 2024. The CPUC plans to issue a proposed decision in connection therewith in early 2021 and subsequently present its report to the California legislature.
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The Utility continues to provide transmission, distribution, metering, and billing services to direct access customers at the election of their energy service provider. The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility. In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges intended to recover the generation-related costs that the Utility incurred on behalf of direct access and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers. SB 520 (codified at Section 387 of the Public Utilities Code), which was signed by the governor and became law on October 2, 2019, allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities.
The Utility is also impacted by the increasing viability of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering (NEM), which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, are increasing, putting upward rate pressure on remaining customers. New NEM customers are required to pay an interconnection fee, utilize time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay. Significantly higher bills for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers or adopt self-generation technologies. The CPUC initiated a proceeding to revisit the NEM tariff in 2020 and has indicated that it anticipates reaching a decision on a revised tariff by the end of 2021.
Further, in some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, may seek to acquire the Utility’s distribution facilities, through eminent domain. In 2020, one such entity communicated an interest in acquiring certain Utility assets through a voluntary sale during the Chapter 11 Cases. It is also expected that some of the governmental entities will construct duplicate or new distribution facilities to serve existing or potential new Utility customers. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities.
The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.
The effect of such types of retail competition generally is to reduce the number of utility customers, leading to a reduction in the amount of electricity purchased from the Utility.
(For risks in connection with increasing competition, see Item 1A. Risk Factors.)
Competition in the Natural Gas Industry
The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
ITEM 1A. RISK FACTORS
PG&E Corporation’s and the Utility’s financial results can be affected by many factors, including estimates and assumptions used in the critical accounting policies described in MD&A, that can cause their actual financial results to differ materially from historical results or from anticipated future financial results. The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2020 Form 10-K. Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Risk Factors Summary
The following is a summary of the principal risks that could adversely affect our business, operations and financial results. These risks are discussed more fully below.
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Risks related to post-chapter 11 environment and financial condition, including risks related to:
•PG&E Corporation’s and the Utility’s substantial indebtedness following the Reorganization;
•Restrictions in indebtedness documents;
•Appeals of the Confirmation Order;
•Potential additional dilution to holders of PG&E Corporation common stock;
•Any substantial sale of stock by existing stockholders;
•Ownership and transfer restrictions associated with PG&E Corporation common stock;
•Tax-related risks and uncertainties, including a potential “grantor trust” election for the Fire Victim Trust;
•Restrictions on PG&E Corporation’s and the Utility’s ability to issue dividends;
•PG&E Corporation’s reliance on dividends, distributions and other payments; and
•The COVID-19 pandemic.
Risks related to wildfires, including risks related to:
•The Utility’s ability to maintain its AB 1054 safety certification and access to the Wildfire Fund;
•The 2020 Zogg fire, the 2019 Kincade fire or future wildfires;
•Recovery of excess costs in connection with wildfires;
•The doctrine of inverse condemnation; and
•Implementation of the PSPS program.
Risks related to the outcome of enforcement matters, investigations, and regulatory proceedings, including risks related to:
•Terms of the Utility’s probation or further modifications to the conditions of probation;
•The Enhanced Oversight and Enforcement Process;
•Legislative and regulatory developments;
•Outcomes of the CPUC’s investigative enforcement proceedings, other known enforcement matters, and other ongoing state and federal investigations and requests for information;
•Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its operating expenses and capital expenditures; and
•The Utility’s continuing ability to recover “pass-through” costs.
Risks related to operations and information technology, including risks related to:
•The hazardous nature of the Utility’s electricity and natural gas operations;
•The Utility’s insurance coverage;
•Changes in the electric power and gas industries;
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•A cyber incident, cyber security breach, severe natural event or physical attack on the Utility’s operational networks and information technology systems; and
•The operation and decommissioning of the Utility’s nuclear generation facilities.
Risks related to environmental factors, including related to:
•Severe weather conditions, extended drought and shifting climate patterns and events resulting from these conditions (including wildfires);
•Extensive environmental laws and changes in or liabilities under these laws; and
•State climate policy requirements.
General risks, including related to:
•Availability of the services of a qualified workforce and to maintain satisfactory collective bargaining agreements.
Risks Related to Post-Chapter 11 Environment and Financial Condition
PG&E Corporation’s and the Utility’s substantial indebtedness following the emergence from the Chapter 11 Cases may adversely affect their financial health and operating flexibility.
PG&E Corporation and the Utility have a substantial amount of indebtedness as a result of the reorganization transactions in connection with implementation of the Plan, most of which is secured by liens on certain assets of PG&E Corporation and the Utility. As of December 31, 2020, PG&E Corporation had approximately $4.71 billion of outstanding indebtedness (such indebtedness consisting of the 2028 Notes, the 2030 Notes and borrowings under the PG&E Corporation Term Loan), and the Utility had approximately $31.9 billion of outstanding indebtedness (such indebtedness including the Utility Reinstated Senior Notes, the New Utility Senior Notes, the Mortgage Bonds, and the Utility Term Loan Credit Agreement). In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $1.9 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.
Since PG&E Corporation and the Utility have a high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility’s assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets. This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including:
•limiting their ability or increasing the costs to refinance their indebtedness;
•limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes;
•limiting their ability to use operating cash flow in other areas of their business;
•increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and
•limiting their ability to capitalize on business opportunities.
Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks. As a result of the high level of indebtedness, PG&E Corporation and the Utility may be unable to generate sufficient cash through operations to service such debt, and may need to refinance such indebtedness at or prior to maturity and be unable to obtain financing on suitable terms or at all, any of which could have a material effect on PG&E Corporation’s and the Utility’s business, financial condition and results of operations.
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The documents that govern PG&E Corporation’s and the Utility’s indebtedness contain restrictions that limit their flexibility in operating their business.
PG&E Corporation’s and the Utility’s material financing agreements, including certain of their respective credit agreements and indentures, contain various covenants restricting, among other things, their ability to:
•incur or assume indebtedness or guarantees of indebtedness;
•incur or assume liens;
•sell or dispose of all or substantially all of its property or business;
•merge or consolidate with other companies;
•enter into any sale leaseback transactions; and
•enter into swap agreements.
The restrictions contained in these material financing agreements could affect PG&E Corporation’s and the Utility’s ability to operate their business and may limit their ability to react to market conditions or take advantage of potential business opportunities as they arise. For example, such restrictions could adversely affect PG&E Corporation’s and the Utility’s ability to finance their operations and expenditures, make strategic acquisitions, investments or alliances, sell assets, restructure their organization or finance their capital needs. Additionally, PG&E Corporation’s and the Utility’s ability to comply with these covenants and restrictions may be affected by events beyond their control, including, but not limited to, prevailing regulatory, economic, financial and industry conditions.
Parties have appealed the Confirmation Order.
Following entry of the Confirmation Order confirming the Plan, certain parties filed notices of appeal with respect to the Confirmation Order. While a number of such appeals have been dismissed, there can be no assurance that any of the remaining appeals will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.
PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.
On the Effective Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Effective Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Effective Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline.
Additionally, PG&E Corporation may be required to pay a material amount of cash with respect to allowed Subordinated Debt Claims (as defined in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8). Such payment may have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.
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Any substantial sale of stock by existing stockholders could depress the market value of PG&E Corporation’s common stock, thereby devaluing the market price and causing investors to risk losing all or part of their investment.
Certain existing stockholders, including the Fire Victim Trust, the PIPE Investors and the Backstop Parties, hold a large number of the outstanding shares of PG&E Corporation. PG&E Corporation can make no prediction as to the effect, if any, that sales of shares, or the availability of shares for future sale, will have on the prevailing market price of shares of PG&E Corporation common stock. Sales of substantial amounts of shares of common stock in the public market, or the perception that such sales could occur, could depress prevailing market prices for such shares. Such sales may also make it more difficult for PG&E Corporation to sell equity securities or equity-linked securities in the future at a time and price which it deems appropriate.
PG&E Corporation may also sell additional shares of common stock in subsequent offerings or issue additional shares of common stock or securities convertible into shares of PG&E Corporation common stock. The issuance of any shares of PG&E Corporation common stock in future financings, acquisitions upon conversion or exercise of convertible securities, or otherwise may result in a reduction of the book value and market price of PG&E Corporation's outstanding common stock. If PG&E Corporation issues any such additional shares, the issuance will cause a reduction in the proportionate ownership and voting power of all current shareholders. PG&E Corporation cannot predict the size of future issuances of shares of PG&E Corporation common stock or securities convertible into shares of PG&E Corporation common stock or, for any issuance, the effect, if any, that such future issuances will have on the market price of PG&E Corporation's common stock.
PG&E Corporation common stock is subject to ownership and transfer restrictions intended to preserve PG&E Corporation’s ability to use its net operating loss carryforwards and other tax attributes.
PG&E Corporation has incurred and may also continue to incur in connection with the Plan significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties. The Amended Articles (as defined below) impose certain restrictions on the transferability and ownership of PG&E Corporation common stock and preferred stock (together, the “capital stock”) and other interests designated as “stock” of PG&E Corporation by the Board of Directors as disclosed in an SEC filing (such stock and other interests, the “Equity Securities,” and such restrictions on transferability and ownership, the “Ownership Restrictions”) in order to reduce the possibility of an equity ownership shift that could result in limitations on PG&E Corporation’s ability to utilize net operating loss carryforwards and other tax attributes from prior taxable years or periods for federal income tax purposes. Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid.
Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities (but see the immediately following risk factor for more information). Any transferee receiving Equity Securities that would result in a violation of the Ownership Restrictions will not be recognized as a shareholder of PG&E Corporation or entitled to any rights of shareholders, including, without limitation, the right to vote and to receive dividends or distributions, whether liquidating or otherwise, in each case, with respect to the Equity Securities causing the violation.
The Ownership Restrictions remain in effect until the earliest of (i) the repeal, amendment or modification of Section 382 (and any comparable successor provision) of the Internal Revenue Code, in a manner that renders the restrictions imposed by Section 382 of the Internal Revenue Code no longer applicable to PG&E Corporation, (ii) the beginning of a taxable year in which the Board of Directors of PG&E Corporation determines that no tax benefits attributable to net operating losses or other tax attributes are available, (iii) the date selected by the Board of Directors if it determines that the limitation amount imposed by Section 382 of the Internal Revenue Code as of such date in the event of an “ownership change” of PG&E Corporation (as defined in Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) would not be materially less than the net operating loss carryforwards or “net unrealized built-in loss” (within the meaning of Section 382 of the Internal Revenue Code and Treasury Regulation Sections 1.1502-91 et seq.) of PG&E Corporation and (iv) the date selected by the Board of Directors if it determines that it is in the best interests of PG&E Corporation’s shareholders for the Ownership Restrictions to be removed or released. The Ownership Restrictions may also be waived by the Board of Directors on a case by case basis.
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If PG&E Corporation elects to treat the Fire Victim Trust as a “grantor trust,” the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act.
The Plan contemplates that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, subject to PG&E Corporation’s ability to elect to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes instead. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock.
If PG&E Corporation were to elect to treat the Fire Victim Trust as a “grantor trust,” any shares owned by the Fire Victim Trust would effectively be excluded from the total number of outstanding Equity Securities when calculating a Person’s Percentage Ownership (as defined in the Amended Articles) for purposes of the Ownership Restrictions. For example, whereas the number of outstanding shares of PG&E Corporation common stock for corporate purposes as of February 22, 2021, was 1,984,683,820 shares, for purposes of the Ownership Restrictions, the number of outstanding common stock as of February 22, 2021, would be 1,506,940,230 (the number of outstanding shares of PG&E Corporation common stock less the number of shares of common stock owned by the Fire Victim Trust as of February 22, 2021). PG&E Corporation does not control the number of shares held by the Fire Victim Trust and is not able to determine in advance the number of shares the Fire Victim Trust will hold. PG&E Corporation intends to periodically make available to investors information about the number of shares of common stock held by the Fire Victim Trust as of a specified date for purposes of the Ownership Restrictions, including in its Quarterly Reports and Annual Reports filed with the SEC.
PG&E Corporation expects to publicly announce its determination on whether it will elect to treat the Fire Victim Trust as a “grantor trust” no later than April 1, 2021. In the event PG&E Corporation decides to make a “grantor trust” election with respect to the Fire Victim Trust, PG&E Corporation intends to enforce the Ownership Restrictions as described in the foregoing paragraph (excluding any shares owned by the Fire Victim Trust from the number of outstanding Equity Securities), including with respect to Transfers (as defined in the Amended Articles) occurring before such announcement. However, it is anticipated that the Board of Directors of PG&E Corporation will exempt Transfers to shareholders occurring prior to July 30, 2020 (the date PG&E Corporation initially announced it was considering treating the Fire Victim Trust as a grantor trust in its Form 10-Q for the quarterly period ended June 30, 2020), solely to the extent that such Transfers would have complied with the Ownership Restrictions if the Ownership Restrictions were applied on the basis that the shares owned by the Fire Victim Trust were treated as outstanding Equity Securities. For the avoidance of doubt, all other Transfers of Equity Securities (including acquisitions from and after the July 30, 2020 by shareholders benefiting from an exemption described in the preceding sentence) will continue to be subject to the Ownership Restrictions. All current and prospective shareholders are advised to consider the foregoing in determining their ownership and acquisition of PG&E Corporation common stock.
The ability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income may be limited.
As of December 31, 2020, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $28.5 billion and $25.4 billion, respectively, and PG&E Corporation incurred and may also continue to incur in connection with the Plan significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the Internal Revenue Code (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years).
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As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code. However, whether PG&E Corporation underwent or will undergo an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects. Accordingly, there can be no assurance that the IRS would not successfully assert that PG&E Corporation has undergone or will undergo an ownership change pursuant to the Plan. In addition, even if these transactions did not cause an ownership change, they may increase the likelihood that PG&E Corporation may undergo an ownership change in the future. If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the Internal Revenue Code could be material to its operations.
In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. Specifically, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to a successful rate-neutral securitization transaction, the proceeds of which are expected to be used to satisfy the Utility’s obligations to the Fire Victim Trust, and to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to consummate a securitization transaction or obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock.
The ability of PG&E Corporation to pay dividends on shares of PG&E Corporation common stock is subject to restrictions.
In response to concerns raised by the California Governor, PG&E Corporation and the Utility filed the Case Resolution Contingency Process Motion with the Bankruptcy Court setting forth certain commitments in connection with the confirmation process and implementation of the Plan, including, among other things, limitations on the ability of PG&E Corporation to pay dividends on shares of its common stock (the “Dividend Restriction”). The Dividend Restriction provides that PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Effective Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items. Additionally, the ruling of the court overseeing the Utility’s probation dated April 3, 2019 places further restrictions on the ability of PG&E Corporation and the Utility to issue dividends. Under those terms of probation, no dividends may be issued until the Utility is fully in compliance with all applicable laws concerning vegetation management and clearance requirements, as well as the vegetation management and enhanced vegetation management targets and metrics in the Utility’s WMP.
Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, PG&E Corporation’s results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant.
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PG&E Corporation is a holding company and relies on dividends, distributions and other payments, advances and transfers of funds from the Utility to meet its obligations.
PG&E Corporation conducts its operations primarily through its subsidiary, the Utility, and substantially all of PG&E Corporation’s consolidated assets are held by the Utility. Accordingly, PG&E Corporation’s cash flow and its ability to meet its debt service obligations under its existing and future indebtedness are largely dependent upon the earnings and cash flows of the Utility and the distribution or other payment of these earnings and cash flows to PG&E Corporation in the form of dividends or loans or advances and repayment of loans and advances from the Utility. The ability of the Utility to pay dividends or make other advances, distributions and transfers of funds will depend on its results of operations and may be restricted by, among other things, applicable laws limiting the amount of funds available for payment of dividends, the conditions of the Utility’s probation proceeding and certain restrictive covenants contained in the agreements of those subsidiaries. Additionally, the Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends and meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. In addition, the CPUC has imposed various conditions that govern the relationship between PG&E Corporation and the Utility, including financial conditions that require the Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. It is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock. The deterioration of income from, or other available assets of, the Utility for any reason could limit or impair the Utility’s ability to pay dividends or other distributions to PG&E Corporation, which could, in turn, materially and adversely affect PG&E Corporation’s ability to meet its obligations.
California law and certain provisions in the Amended Articles and the amended and restated bylaws of PG&E Corporation (the “Amended Bylaws”) may prevent efforts by shareholders to change the direction or management of the Company.
The Amended Articles and the Amended Bylaws contain provisions that may make the acquisition of PG&E Corporation more difficult without the approval of the Board of Directors, including, but not limited to, the following:
•until 2024, the Board of Directors will be divided into two equal classes, with members of each class elected in different years for different terms;
•only holders of shares who are entitled to cast ten percent or more of the votes can request a special meeting of the shareholders, and any such request must satisfy the requirements specified in the Amended Bylaws; action by shareholders may otherwise only be taken at an annual or special meeting duly called by or at the direction of a majority of the Board of Directors;
•advance notice for all shareholder proposals is required; and
•any person acquiring PG&E Corporation Equity Securities will be restricted from owning more than 4.75% of such Equity Securities, subject to certain expectations as may be determined by the Board of Directors of PG&E Corporation.
These and other provisions in the Amended Articles, the Amended Bylaws and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delay or impede a merger, tender offer or proxy contest involving PG&E Corporation. The existence of these provisions could negatively affect the price of PG&E Corporation common stock and limit opportunities for shareholders to realize value in a corporate transaction.
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PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic.
PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been (beginning in March 2020) and could continue to be significantly affected by the outbreak of COVID-19, but the extent of such impact is uncertain. In December 2019, a novel strain of coronavirus (COVID-19) was reported to have surfaced in Wuhan, China, resulting in significant disruptions to manufacturing, supply chain, markets, and travel world-wide. On January 30, 2020, the International Health Regulations Emergency Committee of the World Health Organization declared the COVID-19 outbreak a public health emergency of international concern and on March 12, 2020, announced the outbreak was a pandemic. In response to the California Governor’s emergency proclamation on March 4, 2020, the Utility extended a disconnection moratorium to residential and small business customers. On April 16, 2020, the CPUC approved a resolution requiring utilities to extend this disconnection moratorium through April 16, 2021. On February 11, 2021, the CPUC extended the moratorium for residential and small business customers to June 30, 2021. On December 21, 2020, a CPUC ALJ issued a ruling seeking comments on an approach to implement a temporary moratorium on service disconnections for medium-large commercial and industrial customers. On February 11, 2021, the CPUC initiated a rulemaking proceeding to consider arrearage relief for utility customers who will have outstanding utility bills when the moratorium on service disconnections ends, some of the costs of which could be funded by shareholders.
While the extent of the impact of the current COVID-19 outbreak on PG&E Corporation’s and the Utility’s business and financial results is uncertain, the consequences of a continued and prolonged outbreak and resulting government and regulatory orders have had and could continue to have a further negative impact on the Utility’s financial condition, results of operations, liquidity and cash flows.
The outbreak of COVID-19 and the resulting economic conditions, including but not limited to the shelter-in-place orders, as such orders may be imposed from time to time, and resulting decrease in economic and industrial activity in the Utility’s service territory have and will continue to have a significant adverse impact on the Utility’s customers; these circumstances have impacted and will continue to impact the Utility for a period of time that PG&E Corporation and the Utility are unable to predict. For example, the economic downturn has resulted in a reduction in customer receipts and collection delays in the second, third and fourth quarters of 2020.
The Utility’s customer energy accounts receivable balances over 30 days outstanding as of December 31, 2020 were approximately $825 million, or $478 million higher as compared to the balances as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2021 and for as long as current COVID-19 circumstances persist.
On April 16, 2020, the CPUC passed a resolution requiring COVID-19 related emergency customer protection measures starting from the March 4, 2020 Emergency Proclamation and consistent with the March 16, 2020 Executive Order, through April 16, 2021. On February 11, 2021, the CPUC approved a resolution extending these protections to June 30, 2021. The April 16, 2020 resolution allows associated costs to be tracked in a memorandum account, the CPPMA. The CPPMA allows tracking of residential and small business customers’ incremental uncollectible costs. It is anticipated that implementation of the February 11, 2021 resolution will provide for the same treatment. In addition, the Utility’s 2020 GRC final decision would continue the Utility’s existing mechanism to address uncollectibles, which allows the Utility to readjust its uncollectibles rate on an annual basis based on the most recent 10-year average of uncollectibles. In addition, the June 11, 2020 decision in the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs (Disconnections OIR) provides for a two-way balancing account for residential uncollectibles and memorandum account for OIR implementation costs. The Utility is unable to predict whether these measures will allow for future recovery of these amounts.
In addition, the Utility has experienced average reductions of approximately two percent in electric load and approximately two percent in core gas load on a weather-adjusted basis from mid-March 2020 through December 2020, resulting in an estimated $430 million reduction in billed revenues for the mid-March 2019 to the December 2020 period. On January 1, 2021, electric rates were reset using sales that were adjusted for COVID-19 impacts and significant ongoing shortfalls are not currently expected in 2021. PG&E Corporation and the Utility are currently unable to quantify the long-term potential impact of the changes in customer collections or changes in energy demand on earnings and cash flows due, in part, to uncertainties regarding the timing, duration and intensity of the COVID-19 outbreak and the resulting economic downturn. Although the CPUC authorized the establishment of memorandum and balancing accounts to track costs associated with customer protection measures, the timing of regulatory relief, if any, and ultimately cost recovery from such accounts or otherwise, are uncertain.
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The COVID-19 pandemic and resulting economic downturn have resulted and will continue to result in workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment. In preparation for the return of a few teams to their offices, the Utility has issued a “Return to PG&E Playbook” that explains the safety-related steps the company is taking, as well as the steps that PG&E Corporation’s and the Utility’s employees should take. The guidance includes important reminders of policies on personal hygiene, travel, reporting exposure or illness, and other topics.
Although the Utility continues to prioritize customer and community safety, these disruptions necessitate changes to the Utility’s operating and capital expenditure plans, which could lead to project delays or service disruptions in certain programs. Delays in production and shipping of materials used in the Utility’s operations may also impact operations.
In addition, as discussed above, a group of local government entities and organizations filed a Joint Motion asking the CPUC to require utilities to comply with additional requirements when implementing PSPS events while local areas are sheltering-in-place due to COVID-19. The requested requirements included providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. On August 24, 2020, the ALJ issued a decision holding the April 13, 2020 joint motion in abeyance, finding that the May 28, 2020 decision dealt with many of the issues raised. If the motion were reinstated in the future, a CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.
PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. Potential longer-term impacts of COVID-19 on PG&E Corporation or the Utility include the potential for higher credit spreads and borrowing costs and incremental financing needs. PG&E Corporation’s and the Utility’s analysis of the potential impact of COVID-19 is ongoing and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 situation, the timing, duration or intensity of any resurgence of COVID-19 and any variant strains of the COVID-19 virus, the effectiveness and intensity of measures to contain COVID-19 (including availability and effectiveness of vaccines), and the effects of the COVID-19 situation on the business, financial condition and results of operations of PG&E Corporation and the Utility and on the business and general economic conditions in the State of California and the United States of America.
Risks Related to Wildfires
PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility does not maintain an AB 1054 safety certification or is otherwise unable to access the Wildfire Fund.
On January 14, 2021, the WSD issued the Utility’s 2020 Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The 2020 Safety Certification is valid for 12 months, or until a timely request for a new safety certification is acted upon, whichever occurs later.
The AB 1054 Wildfire Fund disallowance cap, which caps the amount of liability that the Utility could be required to bear for a catastrophic wildfire, is inapplicable if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification at the time the applicable wildfire ignited. The inability to maintain an AB 1054 safety certification and, as a result, the inaccessibility of the disallowance cap on reimbursement to the Wildfire Fund, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, if the Utility has failed to maintain a valid safety certificate at the time a wildfire ignites, the initial burden of proof in a prudency proceeding shifts from intervenors to the Utility.
Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. PG&E Corporation and the Utility will not benefit from all of the features of AB 1054 if the Wildfire Fund is exhausted, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.
PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.
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Based on the facts and circumstances available as of the date of this report, PG&E Corporation and the Utility have determined that it is probable they will incur a loss in connection with the 2019 Kincade fire and the 2020 Zogg fire. Although PG&E Corporation and the Utility have recorded liabilities for probable losses in connection with such wildfires, these liability estimates correspond to the lower end of the range of reasonably estimable losses, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.
Although there are a number of unknown facts surrounding Cal Fire’s causation determination of the 2019 Kincade fire and Cal Fire’s investigation of the 2020 Zogg fire, the Utility could be subject to significant liability in excess of insurance coverage or amounts available under the Wildfire Fund under AB 1054 that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have also received and have responded or are responding to data requests from the CPUC’s SED relating to the 2019 Kincade fire and the 2020 Zogg fire. Furthermore, the Sonoma County District Attorney’s Office and the Shasta County District Attorney’s Office are conducting investigations into the 2019 Kincade fire and the 2020 Zogg fire, respectively. PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.
Although the Utility has taken extensive measures to reduce the threat of future wildfires, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant. This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. See “Risks related to environmental factors—Severe weather conditions, extended drought and shifting climate patterns could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.” Despite significant investment in mitigation measures to improve infrastructure and manage vegetation, as well as implementation of de-energization strategies, the Utility may not be successful in mitigating the risk of future wildfires.
In addition, the 2019 Kincade fire and the 2020 Zogg fire have had and, along with any future wildfires could continue to have adverse consequences on the Utility’s probation proceeding, the Utility’s proceedings with the CPUC and the FERC (including the Safety Culture OII), and future regulatory proceedings, including future applications for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment as a result of the 2019 Kincade fire, 2020 Zogg fire or any future wildfires. For more information about the 2019 Kincade fire and the 2020 Zogg fire, see Note 14 “Wildfire-Related Contingencies” in Part II, Item 8.
If the Utility is unable to recover all or a significant portion of its excess costs in connection with the 2020 Zogg fire and 2019 Kincade fire through ratemaking mechanisms and in a timely manner, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
The Utility could incur substantial costs in excess of insurance coverage in the future in connection with the 2019 Kincade fire and the 2020 Zogg fire.
There can be no assurance that the Utility will be allowed to recover costs in excess of insurance, including costs recorded in those accounts in the future, even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation.
The inability to recover all or a significant portion of costs in excess of insurance through increases in rates and by collecting such rates in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
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The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
California law includes a doctrine of inverse condemnation that is routinely invoked in California. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines. Courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefitted from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Plaintiffs have asserted and continue to assert the doctrine of inverse condemnation in lawsuits related to certain wildfires that occurred in the Utility’s service territory, including the 2019 Kincade fire and the 2020 Zogg fire. While the Utility currently continues to dispute the applicability of inverse condemnation to the Utility, there can be no assurance that the Utility will be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire or other litigation against PG&E Corporation or the Utility.
For example, a court could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. Although the imposition of liability under the doctrine of inverse condemnation is premised on the assumption that utilities have the ability to automatically recover these costs from their customers, there can be no assurance that the CPUC would authorize cost recovery whether or not a previous court decision had imposed liability on a utility under the doctrine of inverse condemnation. (In December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it had incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to the CPUC’s prudent manager standard. That determination was challenged by San Diego Gas & Electric as well as by the Utility and Southern California Edison. In October 2019, the U.S. Supreme Court declined to review the case, effectively ending the challenge.)
If PG&E Corporation or the Utility were to be found liable for damages under the doctrine of inverse condemnation, but the Utility was unable to secure a cost recovery decision from the CPUC to pay for such costs through increases in rates or to collect such rates in a timely manner, the financial condition, results of operations, liquidity, and cash flows of PG&E Corporation and the Utility would be materially affected by potential losses resulting from the impact of the 2019 Kincade fire, the 2020 Zogg fire or any future wildfires. (See “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.” above.)
PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of the Utility’s implementation of its PSPS program.
As outlined in the 2020 WMP, PG&E Corporation and the Utility have adopted the PSPS program to proactively de-energize lines that traverse areas under elevated and extreme risks for wildfire when forecasts predict extreme fire-threat conditions. The Utility carried out nine PSPS events in 2019 and six in 2020. In addition to the 2019 and 2020 PSPS events, the Utility expects that PSPS events will be necessary in 2021 and future years.
These PSPS events have been subject to significant scrutiny and criticism by various stakeholders, including the California Governor, the CPUC and the court overseeing the Utility’s probation. The Utility also is the subject of a scrutiny by the CPUC and of a class action litigation in connection with the 2019 PSPS events that was filed in the Bankruptcy Court in December of 2019. On August 14, 2020, the assigned ALJ issued a scoping memo and ruling in the 2019 ERRA Compliance proceeding that established a Phase II of the proceeding to address the impacts of PSPS events that occurred in the Utility’s service territory in 2019 and how the PSPS impacted its revenue collections. To date, the assigned ALJ has not initiated the Phase II.
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PG&E Corporation and the Utility cannot predict the timing and outcome of the various proceedings and litigation in connection with the PSPS events. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings or other enforcement actions as well as to additional litigation and claims by customers as a result of the Utility’s implementation of its PSPS program, which could result in fines, penalties, customer rebates or other payments. The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future)) or liability for damages could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. (For more information, see “Regulatory Matters” in Item 7. MD&A).
Risks Related to the Outcome of Other Enforcement Matters, Investigations, and Regulatory Proceedings
PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of further non-compliance with the terms of probation or in the event of further modifications to the conditions of probation.
PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of further non-compliance with the terms of probation or in the event of further modifications to the conditions of probation. On January 26, 2017, following the federal criminal trial against the Utility in connection with the San Bruno explosion, in which the Utility was found guilty on six felony counts, the Utility was sentenced to, among other things, a five-year corporate probation period and oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years.
From 2018 to 2020, the court overseeing the Utility’s probation issued various orders related to the Utility’s probation, including a finding that the Utility had violated a condition of its probation with respect to reporting requirements, and imposing new conditions of probation. For more information about the Utility’s probation and the court’s orders, see “Enforcement Matters” in Item 7. MD&A.
The Utility could incur material costs, not recoverable through rates, in the event of further non-compliance with the terms of its probation and in connection with the monitorship (including but not limited to costs resulting from recommendations of the third-party monitor). The Utility could also incur material costs, not recoverable through rates, in the event of further modifications to the conditions of its probation, such as those proposed by the court overseeing the Utility’s probation on December 29, 2020 and February 4, 2021, relating to de-energizing certain distribution circuits during PSPS events based on the presence of certain vegetation, and on February 18, 2021, relating to removing all trees or portions thereof, without regard to their health, if they are leaning towards a distribution line and could either fall on the line or contact the line from the side.
The outcome of probation could harm the Utility’s relationships with customers, regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management. Further, it could negatively affect the outcome of future ratemaking and regulatory proceedings and result in increased regulatory or legislative scrutiny, including with respect to various aspects of how the Utility’s business is conducted or organized. (See “Enforcement and Litigation Matters” in Item 7. MD&A.)
PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of an Enhanced Oversight and Enforcement Process.
On November 24, 2020, the Utility received a letter (the “Letter”) from the President of the CPUC, expressing concerns related to the Utility’s vegetation management and asset management activities and explaining potential implications with respect to the Enhanced Oversight and Enforcement Process adopted by the CPUC in its decision approving PG&E Corporation’s and the Utility’s Plan, as well as the Utility’s annual safety certification under AB 1054. According to the Letter, the President of the CPUC has “directed CPUC staff to conduct fact-finding to determine whether a recommendation to place [the Utility] into the enhanced oversight and enforcement process is warranted.” On January 14, 2021, the WSD issued the Utility’s 2020 Safety Certification pursuant to AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations.
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The Enhanced Oversight and Enforcement Process is a six-step process with potentially escalating CPUC oversight and enforcement measures based on specific “triggering events” identified for each of the six steps. If the Utility is placed into the Enhanced Oversight and Enforcement Process, it will be subject to additional reporting requirements and additional monitoring and oversight by the CPUC. Higher steps of the process (Steps 3-6) also contemplate additional enforcement mechanisms, including appointment of an independent third-party monitor, appointment of a chief restructuring officer, pursuit of the receivership remedy, and review of the Utility’s Certificate of Public Convenience and Necessity (i.e., its license to operate as a utility). The process contains provisions for the Utility to cure and exit the process if it can satisfy specific criteria. The Enhanced Oversight and Enforcement Process states that the Utility should presumptively move through the steps of the process sequentially, but the CPUC may place the Utility into the appropriate step of the process upon occurrence of a specified triggering event.
PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of legislative and regulatory developments.
Pursuant to Article 5.8 of the Public Utilities Code, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust. Failure to consummate a securitization transaction could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. (See “Regulatory Matters - Other Regulatory Proceedings” in Item 7. MD&A.)
In addition, the Public Utilities Code requires utilities to submit annual WMPs for approval by the CPUC on a schedule to be established by the CPUC. If the CPUC rejects the Utility’s WMP submittal, the Utility would become unable to obtain an AB 1054 safety certification and, as a result, become unable to access the Wildfire Fund, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The statute establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan. Failure to substantially comply with the plan could result in fines and other penalties imposed on the Utility that could be material. (See “Regulatory Matters – Other Regulatory Proceedings” in Item 7. MD&A.)
On July 12, 2019, the California Governor signed into law AB 1054, which, among other policy reforms, provides for the establishment of a statewide fund that is 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. Although PG&E Corporation and the Utility contributed in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund on the Effective Date of the Plan to allow participation of the Utility therein, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund are just and reasonable, subject to a disallowance cap, and that the Wildfire Fund has sufficient remaining funds. The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. (See also, “PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility does not maintain an AB1054 safety certification or is otherwise unable to access the Wildfire Fund.” above.)
The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the anticipated ten-year life of the fund. The timing and amount of any potential charges associated with the Utility’s contributions would also depend on various factors. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing on which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.
Finally, AB 1054 revised some of the SB 901 requirements regarding WMPs, including creating a WSD to review future plans and that plans should cover a three-year period.
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In June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. On October 11, 2019, the State of California announced proposed regulations which provide guidance on the requirements of the CCPA. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that creates the California Privacy Rights Act (CPRA). The CPRA, which will become effective on January 1, 2023, amends and expands the CCPA. Failure to comply with the CCPA and the CPRA could result in fines imposed on PG&E Corporation and the Utility that could be material.
Also, on September 10, 2018, the California Governor signed into law SB 100 (the 100 Percent Clean Energy Act of 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. Failure to comply with SB 100 could result in fines imposed on PG&E Corporation and the Utility that could be material and could also result in negative publicity.
Finally, on June 30, 2020, the California Governor signed into law SB 350 (the Golden State Energy Act), a bill which authorizes the creation by the 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 only in the event that the CPUC determines that the Utility’s Certificate of Public Convenience and Necessity should be revoked pursuant to any process or procedures adopted by the CPUC in its decision approving PG&E Corporation’s and the Utility’s Plan of Reorganization.
The Utility is subject to extensive regulations and the risk of enforcement proceedings in connection with compliance with such regulations. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by the outcomes of the CPUC’s investigative enforcement proceedings against the Utility, other known enforcement matters, and other ongoing state and federal investigations and requests for information.
The Utility is subject to extensive regulations, including federal, state and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with the order to show cause related to the 2019 PSPS events, the OII related to the 2019 PSPS events, the safety culture OII, and other matters that the CPUC’s SED may be investigating. The SED could launch investigations at any time on any issue it deems appropriate.
The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and resource adequacy requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC general orders or other applicable CPUC decisions or regulations; federal electric reliability standards; and environmental compliance. CPUC staff could also impose penalties on the Utility in the future in accordance with its authority under the gas and electric safety citation programs. The amount of such fines, penalties, or customer refunds could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility also is a target of a number of investigations, in addition to certain investigations in connection with the wildfires. (See “Risks Related to Wildfires,” above.) The Utility is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility, or the amount of any costs and expenses associated with such investigations.
If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties the amount of which could be substantial and, in the event of a judgment against the Utility, suffer further ongoing negative consequences. Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the Utility’s violations. (See also “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of further non-compliance with the terms of probation or in the event of modifications to the conditions of probation” above.)
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PG&E Corporation’s and the Utility’s financial results primarily depend on the outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its operating expenses and capital expenditures so that it is able to earn its authorized rate of return in a timely manner.
As a regulated entity, the Utility’s rates are set by the CPUC or the FERC on a prospective basis and are generally designed to allow the Utility to collect sufficient revenues to recover reasonable costs of providing service, including a return on its capital investments. PG&E Corporation’s and the Utility’s financial results could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility to safely and reliably serve its customers and earn its authorized ROE. The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services. Further, an increase in the amount of capacity located in the Utility’s service territory that is procured by the CAISO could increase the Utility’s costs of procuring capacity needed for reliable service to its customers.
In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility’s actual costs to safely and reliably serve its customers differ from authorized or forecast costs. The Utility may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as wildfires, storms, earthquakes, accidents, or catastrophic or other events affecting the Utility’s operations), or compliance with new state laws or policies. Although the Utility may be allowed to recover some or all of the additional costs, there may be a substantial delay between when the Utility incurs the costs and when the Utility is authorized to collect revenues to recover such costs. Alternatively, the CPUC or the FERC may disallow costs that they determine were not reasonably or prudently incurred by the Utility.
The Utility also is required to incur costs to comply with legislative and regulatory requirements and initiatives, such as those relating to the development of a state-wide electric vehicle charging infrastructure, the deployment of distributed energy resources, implementation of demand response and customer energy efficiency programs, energy storage and renewable energy targets, underground gas storage, and the construction of the California high-speed rail project. The Utility’s ability to recover costs, including its investments, associated with these and other legislative and regulatory initiatives will depend, in large part, on the final form of legislative or regulatory requirements, and the associated ratemaking mechanisms associated with these initiatives, including the timely adjustment of such mechanisms to reflect any lowered customer demand for the Utility’s electricity and natural gas services.
PG&E Corporation’s and the Utility’s financial results depend upon the Utility’s continuing ability to recover “pass-through” costs, including electricity and natural gas procurement costs, from customers in a timely manner. The CPUC may disallow procurement costs for a variety of reasons. In addition, the Utility’s ability to recover these costs could be affected by the loss of Utility customers and decreased new customer growth, if the CPUC fails to adjust the Utility’s rates to reflect such events.
The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility’s own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market. The Utility must manage these sources using the commercial and CPUC regulatory principles of “least cost dispatch” and prudent administration of power purchase agreements in compliance with its CPUC-approved long-term procurement plan. The CPUC could disallow procurement costs incurred by the Utility if the CPUC determines that the Utility did not comply with these principles or if the Utility did not comply with its procurement plan.
Further, the contractual prices for electricity under the Utility’s current or future power purchase agreements could become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to adverse economic conditions or the loss of the Utility’s customers to other retail providers. Despite the CPUC’s current approval of the contracts, the CPUC could disallow contract costs in the future if it determines that the terms of such contracts, including price, do not meet the CPUC reasonableness standard.
The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by whether the CAISO wholesale electricity market continues to function effectively. Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended which could result in excessive market prices. The CPUC could prohibit the Utility from passing through the higher costs of electricity to customers.
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Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreasing bundled load that occurs through municipalization of the Utility’s facilities, an increase in the number of CCAs that provide electricity to their residents, and an increase in the number of consumers who become direct access customers of alternative generation providers. (See “Competition in the Electricity Industry” in Item 1.) As the number of bundled customers (i.e., those customers who receive electricity and distribution service from the Utility) declines, the rates for remaining customers could increase as the Utility would have a smaller customer base from which to recover certain procurement costs. Although the Utility is permitted to collect non-bypassable charges for above market generation-related costs incurred on behalf of former customers, the charges may not be sufficient for the Utility to fully recover these costs. In addition, the Utility’s ability to collect non-bypassable charges has been, and may continue to be, challenged by certain customer groups. Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.
In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer NEM, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, puts upward rate pressure on remaining customers, who may incur significantly higher bills due to an increase in customers seeking alternative energy providers.
A confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments. If the number of the Utility’s customers decreases or grows at a slower rate than anticipated, the Utility’s level of authorized capital investment could decline as well, leading to a slower growth in rate base and earnings. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could materially affect PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows.
Further, changes in commodity prices also may have an adverse effect on the Utility’s ability to timely recover its operating costs and earn its authorized ROE. Although the Utility generally recovers its electricity and natural gas procurement costs from customers as “pass-through” costs, a significant and sustained rise in commodity prices could create overall rate pressures that make it more difficult for the Utility to recover its costs that are not categorized as “pass-through” costs. To relieve some of this upward rate pressure, the CPUC could authorize lower revenues than the Utility requested or disallow full cost recovery.
If the Utility is unable to recover a material portion of its procurement costs and/or if the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, the wide deployment of distributed generation, and the development of new electricity generation and energy storage technologies, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
Risks Related to Operations and Information Technology
The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. (See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. Business above.) The Utility’s ability to earn its authorized ROE depends on its ability to efficiently maintain, operate, and protect its facilities, and provide electricity and natural gas services safely and reliably. The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities. In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives, and the CPUC approved retirement of Diablo Canyon by 2024 and 2025.
The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from:
•the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption or other catastrophic events;
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•an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow;
•the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;
•a prolonged statewide electrical black-out that results in damage to the Utility’s equipment or damage to property owned by customers or other third parties;
•the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage;
•the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;
•the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;
•the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion);
•inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;
•operator or other human error;
•a motor vehicle incident involving a Utility vehicle (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences;
•an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently;
•construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines;
•the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and
•attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
The occurrence of any of these events could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death. As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any of such incidents also could lead to significant claims against the Utility.
Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities, vegetation management, or the construction or demolition or facilities, the Utility may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.
Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
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The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events and events resulting from these conditions (including wildfires), or may not be available at a reasonable cost, or available at all.
The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires and other risks that could arise from the Utility’s ordinary operations. PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss that is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
As a result of the potential application to IOUs of a strict liability standard under the doctrine of inverse condemnation, recent losses recorded by insurance companies, past wildfires and the risk of increased wildfires including as a result of climate change, the Utility may not be able to obtain sufficient insurance coverage in the future at a reasonable cost, or at all. In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses. Also, the Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. The Wildfire Fund would be available to the Utility to pay eligible claims for liabilities arising from future wildfires and would serve as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. (See “Insurance Coverage” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to obtain insurance at a reasonable cost or recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
The electric power and gas industries are undergoing significant changes driven by technological advancements and a decarbonized economy, which could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.
The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. The electric grid is a critical enabler of the adoption of new energy technologies that support California’s climate change and GHG reduction objectives, which continue to be publicly supported by California policymakers. California's environmental policy objectives are accelerating the pace and scope of the industry change. For instance, SB 100, which was signed into law on September 10, 2018, increases from 50% to 60%, the percentage of California’s electricity portfolio that must come from renewables by 2030. SB 100 establishes a further goal to have an electric grid that is entirely powered by clean energy by 2045. California utilities also are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies. These developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid’s capacity, and interconnect DERs.
In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and state infrastructure modernization (e.g., rail and water projects).
To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs and, consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. The CPUC also authorized development of two new, five-year programs aimed at accelerating widespread electric vehicle adoption and combating climate change. The new programs will increase fast charging options for consumers as well as electric charging infrastructure for non-light-duty fleet vehicles.
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In addition, in light of the state’s commitment to clean energy and carbon neutral economy by 2045, California has recently proposed public policies that prohibit or restrict the use and consumption of natural gas, for example in buildings, that will have for effect to reduce the use of natural gas. Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer be “used and useful,” potentially causing substantial investment value of gas assets to be stranded. (Under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which may result in a reduction in associated rate recovery.) However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements. Inability by the Utility to recover in rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.
The industry changes, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric and gas industry, could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.
A cyber incident, cyber security breach, severe natural event or physical attack on the Utility’s operational networks and information technology systems could have a material effect on its financial condition, results of operations, liquidity, and cash flows.
The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks. Private and public entities, such as the North American Electric Reliability Corporation, and the U.S. Federal government, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.
The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers. In addition, the Utility is increasingly being required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California’s electricity market related to grid modernization and customer choice. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.
The Utility and its third-party vendors have been subject to, and will likely continue to be subject to, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations. None of these breaches or attempts has individually or in the aggregate resulted in a security incident with a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.
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The operation and decommissioning of the Utility’s nuclear generation facilities expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements or operating conditions change or the facilities cease operations before the licenses expire.
The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to operation of the Diablo Canyon nuclear generation units as well as the storage, handling and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the Utility may be required under federal law to pay up to $275 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States.
On January 11, 2018, the CPUC approved the retirement of Diablo Canyon units by 2024 and 2025. However, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation. As a result, operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before their respective licenses expire in 2024 and 2025. In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
In addition, in order to retain highly skilled personnel necessary to safely operate Diablo Canyon during the remaining years of operations, the Utility will incur costs in connection with (i) an employee retention program to ensure adequate staffing levels at Diablo Canyon, which program has been approved by the CPUC, and (ii) an employee retraining and development program, to facilitate redeployment of a portion of Diablo Canyon personnel to the decommissioning project and elsewhere in the Utility. There can be no assurance that the Utility will be successful in retaining highly skilled personnel under its employee programs.
The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. (See “Regulatory Environment” in Item 1. Business above.) If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial results could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions. The Utility may incur a material charge if it ceases operations at Diablo Canyon’s two nuclear generation units before their respective licenses expire in 2024 and 2025. At December 31, 2020, the Utility’s unrecovered investment in Diablo Canyon was $1.4 billion.
The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. (See Note 3: Summary of Significant Accounting Policies - “Asset Retirement Obligations” of the Notes to the Consolidated Financial Statement in Item 8.) The CPUC authorizes the Utility to recover its estimated costs to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. If the Utility is unable to adequately address the vibration issues in the Unit 2 generator, it may be required to operate Unit 2 at reduced operating levels or take the unit out of service for additional inspection, maintenance, or replacement of the affected component. Actions that may be necessary in response to the vibrations affecting the generator, or the occurrence or length of future outages, may result in incremental costs or forgone power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC. If additional outages occur in the future, or if Unit 2’s planned spring 2021 refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur additional incremental costs or forgo additional power market revenues. Furthermore, the cost of such actions may exceed current estimates, such costs may not be fully recovered from insurance through NEIL, or the costs may not be recovered through regulatory processes or otherwise. These amounts could be material and have a material effect on the Utility’s financial condition, results of operations, liquidity and cash flows.
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Risks Related to Environmental Factors
Severe weather conditions, extended drought and shifting climate patterns could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Extreme weather, drought and shifting climate patterns have intensified the challenges associated with wildfire management in California. The Utility’s service territory encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as drought conditions followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihood and severity of extraordinary wildfire events. In particular, the risk posed by wildfires has increased in the Utility’s service area as a result of a prior extended period of drought, bark beetle infestations in the California forest and wildfire fuel increases due to rising temperatures and record rainfall following the drought, and strong wind events, among other environmental factors. Contributing factors other than environmental can include local land use policies and historical forestry management practices. The combined effects of extreme weather and climate change also impact this risk. According to CalFire, as of December 12, 2020, over 9,639 fires have burned 4,359,517 acres, more than four percent of the state’s roughly 100 million acres of land, making 2020 the largest wildfire season recorded in California’s modern history. In January 2018, the CPUC approved a statewide fire-threat map that shows that approximately half of the Utility’s service territory is facing “elevated” or “extreme” fire danger. Approximately 25,000 circuit miles of the Utility’s nearly 81,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such high-fire threat areas, significantly more in total than other California IOUs.
Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, heat waves, drought, earthquakes, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, or other natural disasters such as wildfires, could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to PG&E Corporation and the Utility. Any such event could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Any of such events also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices and/or the failure of electric and other equipment of the Utility.
Further, the Utility has been studying the potential effects of climate change (increased temperatures, changing precipitation patterns, rising sea levels) on its assets, operations, and services, as part of its CVA. Following completion of this assessment, the Utility is developing adaptation plans to set forth a strategy for those events and conditions that the Utility believes are most significant. Scientists project that climate change will increase electricity demand due to more extreme, persistent and hot weather. As a result, the Utility’s hydroelectric generation could change, and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, climate hazards such as heatwaves, wind storms, and flooding caused by rising sea levels and extreme storms could damage the Utility’s facilities, including gas, generation, and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase.
Events or conditions caused by climate change could have a greater impact on the Utility’s operations than the Utility’s studies suggest and could result in lower revenues or increased expenses, or both. If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
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The Utility’s operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation’s and the Utility’s financial results.
The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, and orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife. The Utility incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations. The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)
Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions.
The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.
Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. (See “Environmental Regulation” in Item 1. and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial results. Their financial results also can be materially affected by changes in estimated costs and by the extent to which actual remediation costs differ from recorded liabilities.
State climate policy requires reductions in greenhouse gas emissions of 40% by 2030 and 80% by 2050. Various proposals for addressing these reductions have the potential to reduce natural gas usage and increase natural gas costs, which may impact the future of natural gas services. The future recovery of the increased costs associated with compliance is uncertain.
The CARB is the state’s primary regulator for GHG emission reduction programs. Natural gas providers have been subject to compliance with CARB’s Cap-and-Trade Program since 2015, and natural gas end-use customers have an increasing exposure to carbon costs under the Program through 2030 when the full cost will be reflected in customer bills. CARB’s Scoping Plan also proposes various methods of reducing GHG emissions from natural gas. These include more aggressive energy efficiency programs to reduce natural gas end use, increased renewable portfolio standards generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances, leading to further reduced demand. These natural gas load reductions may be partially offset by CARB’s proposals to deploy natural gas to replace wood fuel in home heating and diesel in transportation applications. CARB also proposes a displacement of some conventional natural gas with above-market renewable natural gas. The combination of reduced load and increased costs could result in higher natural gas customer bills and a potential mandate to deliver renewable natural gas could lead to cost recovery risk. In addition, local city governments have passed ordinances restricting use of natural gas in new construction, and if other jurisdictions follow suit, this could affect future demand for the provision of natural gas.
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General Risk Factors
The Utility’s success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees. PG&E Corporation’s and the Utility’s results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.
The Utility’s workforce is aging, and many employees are or will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may be faced with a shortage of experienced and qualified personnel. The majority of the Utility’s employees are covered by collective bargaining agreements with three unions. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements with the unions or if tentative new agreements are not ratified by their members. In addition, some of the remaining non-represented Utility employees could join one of these unions in the future.
PG&E Corporation and the Utility also may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the ongoing enforcement proceedings and the recent Chapter 11 Cases. Any such occurrences could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility’s electricity and natural gas distribution facilities, electric generation facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, which are described in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.” The Utility occupies or uses real property primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies 11 million square feet of real property, including 9 million square feet owned by the Utility. The Utility’s corporate headquarters comprises approximately 1.7 million square feet located in several Utility-owned buildings in San Francisco, California. The Utility intends to sell its current corporate headquarters office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California, and associated properties owned by the Utility, and on September 30, 2020, the Utility filed an application seeking the required CPUC approval. On October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the building located at 300 Lakeside Drive, Oakland, California, 94612 (“Lakeside Building”) to serve as the Utility’s principal administrative headquarters. The term of the lease will begin on or about March 1, 2022 and will grant the Utility an option to purchase the legal parcel that contains the Lakeside Building. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease will expire in 2022.
The Utility currently owns approximately 158,000 acres of land, including approximately 128,000 acres of watershed lands. In 2002, the Utility agreed to implement its LCC to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations. The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Utility’s goal is to implement all the transactions needed to implement the LCC by the end of 2022, subject to securing all required regulatory approvals.
ITEM 3. LEGAL PROCEEDINGS
PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see Item 7. MD&A: “Enforcement and Litigation Matters,” Item 1A. Risk Factors and Notes 2, 14, and 15 of the Notes to the Consolidated Financial Statements in Item 8.
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During the quarter ended December 31, 2020, PG&E Corporation and the Utility increased their quantitative threshold for disclosure of environmental proceedings from $100,000 in prior years to $1 million as a result of amendments to disclosure requirements in Regulation S-K.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following individuals serve as executive officers of PG&E Corporation, as of February 25, 2021. Except as otherwise noted, all positions have been held at PG&E Corporation.
| Name | Age | Positions Held Over Last Five Years | Time in Position | |||||||||||||||||
| Patricia K. Poppe | 52 | Chief Executive Officer | January 4, 2021 to present | |||||||||||||||||
| Chief Executive Officer, CMS Energy Corporation | July 2016 to December 2020 | |||||||||||||||||||
| President of customer experience, rates and regulation of Consumers, CMS Energy Corporation | January 2011 to July 2016 | |||||||||||||||||||
| Christopher A. Foster | 42 | Interim Chief Financial Officer | September 26, 2020 to present | |||||||||||||||||
| Vice President, Treasury and Investor Relations | March 9, 2020 to September 25, 2020 | |||||||||||||||||||
| Senior positions within PG&E Corporation’s Investor Relations department, including as its Vice President starting in December 2018 | November 2017 to March 8, 2020 | |||||||||||||||||||
| Senior positions within PG&E Corporation and the Utility, including Director, Integrated Grid Planning and Innovation from June 2016 to October 2017 and Chief of Staff, Office of the Chairman and CEO, from June 2014 to May 2016 | September 6, 2011 to October 2017 | |||||||||||||||||||
| Adam L. Wright | 43 | Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company | February 1, 2021 to present | |||||||||||||||||
| Chief Executive Officer and President, MidAmerican | January 2018 to January 26, 2021 | |||||||||||||||||||
| President of MidAmerican Funding LLC | January 2018 to January 26, 2021 | |||||||||||||||||||
| Vice President, Gas Delivery, MidAmerican | May 2015 to January 2018 | |||||||||||||||||||
| Vice President, Wind Generation & Development, MidAmerican | January 2012 to May 2015 | |||||||||||||||||||
| John R. Simon | 56 | Executive Vice President, General Counsel and Chief Ethics & Compliance Officer | August 15, 2020 to present | |||||||||||||||||
| Executive Vice President, Law, Strategy, and Policy | June 3, 2019 to August 15, 2020 | |||||||||||||||||||
| Executive Vice President | May 2, 2019 to June 2, 2019 | |||||||||||||||||||
| Interim Chief Executive Officer | January 13, 2019 to May 1, 2019 | |||||||||||||||||||
| Executive Vice President and General Counsel | March 1, 2017 to January 13, 2019 | |||||||||||||||||||
| Executive Vice President, Corporate Services and Human Resources | August 18, 2015 to February 28, 2017 | |||||||||||||||||||
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The following individuals serve as executive officers of the Utility as of February 25, 2021. Except as otherwise noted, all positions have been held at the Utility.
| Adam L. Wright | 43 | Executive Vice President, Operations and Chief Operating Officer | February 1, 2021 to present | |||||||||||||||||
| Chief Executive Officer and President, MidAmerican | January 2018 to January 26, 2021 | |||||||||||||||||||
| President of MidAmerican Funding LLC | January 2018 to January 26, 2021 | |||||||||||||||||||
| Vice President, Gas Delivery, MidAmerican | May 2015 to January 2018 | |||||||||||||||||||
| Vice President, Wind Generation & Development, MidAmerican | January 2012 to May 2015 | |||||||||||||||||||
| David S. Thomason | 45 | Vice President, Chief Financial Officer, and Controller, Pacific Gas and Electric Company | June 1, 2016 to present | |||||||||||||||||
| Vice President and Controller, PG&E Corporation | June 1, 2016 to present | |||||||||||||||||||
| Senior Director, Financial Forecasting and Analysis | March 2, 2015 to May 31, 2016 | |||||||||||||||||||
| Senior Director, Corporate Accounting | March 2, 2014 to March 1, 2015 | |||||||||||||||||||
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of February 22, 2021, there were 46,536 holders of record of PG&E Corporation common stock. A substantially greater number of holders of PG&E Corporation common stock are “street name” or beneficial holders, whose shares of record are held by banks, brokers, and other financial institutions. PG&E Corporation common stock is listed on the New York Stock Exchange and is traded under the symbol “PCG.” Shares of common stock of the Utility are wholly owned by PG&E Corporation. On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018. (See “Liquidity and Financial Resources - Dividends” in Item 7. MD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 and Note 7 of the Notes to the Consolidated Financial Statements in Item 8.)
Sales of Unregistered Equity Securities
During the quarter ended December 31, 2020, PG&E Corporation did not make any equity contributions to the Utility. Also, PG&E Corporation did not make any sales of unregistered securities during the fiscal year ended December 31, 2020 that were not previously disclosed in a quarterly report on Form 10-Q or a current report on Form 8-K.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2020, PG&E Corporation did not redeem or repurchase any shares of common stock or equity units outstanding. PG&E Corporation does not have any preferred stock outstanding. Also, during the quarter ended December 31, 2020, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
ITEM 6. SELECTED FINANCIAL DATA
Not applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.
The Utility’s base revenue requirements are set by the CPUC in its GRC and GT&S rate case based on forecast costs. Differences between forecast costs and actual costs can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. Generally, differences between actual costs and forecast costs affect the Utility’s ability to earn its authorized return (referred to as “Utility Revenues and Costs that Impacted Earnings” in Results of Operations below). The Utility’s base transmission revenue requirements are recovered through a formula rate approved by the FERC that trues up forecast and actual costs. For certain operating costs, such as costs associated with pension benefits, the Utility is authorized to track the difference between actual amounts and forecast amounts and recover or refund the difference through rates (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below). The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers, such as the costs to procure electricity or natural gas for its customers. Therefore, although these costs can fluctuate, they generally do not impact net income (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below). See “Ratemaking Mechanisms” in Item 1. Business for further discussion.
This is a combined report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8.
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Chapter 11 Proceedings and Emergence
On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. On the Effective Date, PG&E Corporation and the Utility emerged from Chapter 11, pursuant to the Plan, which was approved by the Bankruptcy Court in the Confirmation Order. However, certain parties have filed notices of appeal with respect to the Confirmation Order, including provisions related to the injunction contained in the Plan that channels certain pre-petition fire-related claims to trusts to be satisfied from the trusts’ assets.
For more information about the Chapter 11 Cases, Chapter 11 emergence and the related transactions, see “Liquidity and Financial Resources” below and Notes 2, 5 and 6 of the Notes to the Consolidated Financial Statements in Item 8 of this 2020 Form 10-K.
Tax Matters
As a result of the Plan, which includes wildfire settlement payments made in the third quarter of 2020, PG&E Corporation had a federal net operating loss carryforward of approximately $28.5 billion and state net operating loss carryforward of $25.4 billion at the end of 2020.
Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” the calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility issued to the Fire Victim Trust 477.0 million shares of PG&E Corporation’s common stock. On the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.2 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.
In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of December 31, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. As discussed further below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” PG&E Corporation believes benefits associated with “grantor trust” treatment could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation common stock. PG&E Corporation expects to elect grantor trust treatment, subject to entering into a definitive agreement with the Fire Victim Trust. There can be no assurance that such an agreement will be reached or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election.
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At December 31, 2020, PG&E Corporation’s Consolidated Financial Statements reflect “qualified settlement fund” treatment. If PG&E Corporation were to make a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares. The value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust were to be treated as a “qualified settlement fund.” Additionally, $5.4 billion of cash and $4.54 billion of PG&E Corporation common stock, in the aggregate $10.0 billion that was transferred to the Fire Victim Trust in 2020 will not be deductible for tax purposes until the trust pays the fire victims. Consequently, PG&E Corporation’s net operating loss will decrease by approximately $10.0 billion and result in a $1.3 billion charge, net of tax, decreasing net deferred tax assets by $1.3 billion on its Consolidated Financial Statements for activity through December 31, 2020. PG&E Corporation will subsequently recognize income tax benefits and the corresponding deferred tax asset as the Fire Victim Trust sells the shares.
Update on Ownership Restrictions in PG&E Corporation’s Amended Articles
The Plan contemplates that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, subject to PG&E Corporation’s ability to elect to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes instead. Based on the facts known to date, PG&E Corporation believes benefits associated with the “grantor trust” treatment could be realized for U.S. federal income tax purposes. (See “Tax Matters” above for more information.)
If PG&E Corporation were to make a “grantor trust” election with respect to the Fire Victim Trust, then any shares owned by the Fire Victim Trust would effectively be excluded from the total number of outstanding equity securities when calculating a person’s percentage ownership for purposes of the 4.75 percent ownership limitation in PG&E Corporation's charter. For example, although PG&E Corporation had 1,984,683,820 shares outstanding as of February 22, 2021, only 1,506,940,230 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust) would count as outstanding for purposes of the ownership restrictions in the Amended Articles. As of February 22, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock.
Summary of Changes in Net Income and Earnings per Share
PG&E Corporation’s net loss attributable to common shareholders was $1.3 billion in 2020, compared to $7.7 billion in 2019. PG&E Corporation recognized charges of $56 million and $195 million, net of probable insurance recoveries, for claims in connection with the 2020 Zogg fire and the 2019 Kincade fire, respectively, for the year ended December 31, 2020, compared to charges of $11.4 billion for claims in connection with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire for the year ended December 31, 2019. Additionally, PG&E Corporation recognized $1.1 billion of expense related to the Backstop Commitment Premium Shares and $452 million of expense related to the Additional Backstop Premium Shares for the year ended December 31, 2020, with no similar amounts in 2019.
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Key Factors Affecting Financial Results
PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be materially affected by the following factors:
•The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. To the extent that future wildfires occur in the Utility’s service territory, the Utility may incur costs associated with the investigations of the causes and origins of such fires, even if it is subsequently determined that such fires were not caused by the Utility’s facilities. The financial impact of future wildfires could be mitigated through insurance, the Wildfire Fund or other forms of cost recovery. However, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. In July and August 2020, the Utility renewed its liability insurance coverage for wildfire events in the aggregate amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund is available to the Utility to pay eligible claims for liabilities arising from future wildfires and serves as an alternative to traditional insurance products, provided that the Utility satisfies the conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. (See “Insurance Coverage” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility’s emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims would be capped at 40% of the amount of such claims. (See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
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•The Uncertainties Regarding the Impact of Public Safety Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility’s wildfire risk mitigation initiatives outlined in the 2019 WMP and included in the 2020-2022 WMP, has been the subject of significant scrutiny and criticism by various stakeholders, including the California governor, the CPUC and the court overseeing the Utility’s probation. On November 12, 2019, the CPUC issued an order to show cause against the Utility related to implementation of the October 2019 PSPS events, and on November 13, 2019, the CPUC instituted an OII to examine California’s IOUs late 2019 PSPS events and to consider enforcement actions. In their comments submitted to the CPUC on October 16, 2020 in the OII to Examine the Late 2019 Public Safety Power Shutoff Events, TURN, an intervenor in this proceeding, proposed that the CPUC should treat each customer affected by a PSPS event, for which the IOU has not adequately demonstrated that the benefits outweigh the public safety risks, as a separate offense. Under the CPUC rules, each offense would be subject to a penalty of no less than $500 and no more than $100,000. On October 30, 2020, Cal Advocates, an intervenor in the Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events proposed financial penalties against the Utility of $166 million. If adopted by the CPUC, such penalties could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. The PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. In addition to the 2019 PSPS events, the Utility initiated several PSPS events in the third and fourth quarters of 2020 and one in January 2021 and expects that additional PSPS events will be necessary in future years. (See “OII to Examine the Late 2019 Public Safety Power Shutoff Events” and “OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions” in “Regulatory Matters” below.)
•The Costs and Execution of Other Wildfire Mitigation Efforts. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events. PG&E Corporation and the Utility incurred approximately $2.6 billion in connection with the 2019 WMP and incurred approximately $2.9 billion in 2020 in connection with the 2020-2022 WMP. Although the Utility may seek cost recovery for certain of these expenses and capital expenditures, the Utility has agreed in the Wildfires OII not to seek rate recovery of certain wildfire-related expenses and capital expenditures that it has incurred or will incur in the amount of $1.823 billion in future applications.
While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. For example, the Court overseeing the Utility’s probation in connection with the Utility’s federal criminal proceeding has imposed numerous obligations on the Utility related to its business and operations. The success of the Utility’s wildfire mitigation efforts depends on many factors, including on whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions. (See “U.S. District Court Matters and Probation” and “2020 General Rate Case” below and “Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)
•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its FERC TO18 and TO19 rate cases, WMCE application, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, WMPMA, FRMMA, CPPMA, VMBA, WMBA, and RTBA. The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors. The Utility’s ability to seek cost recovery will also be limited as a result of the outcome of the Wildfires OII. (See Notes 4 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below.)
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•The Impact of the 2019 Kincade Fire. Claims related to the 2019 Kincade fire that were not satisfied in full as of the Effective Date were not discharged in connection with emerging from Chapter 11. On July 16, 2020, Cal Fire issued a press release stating that it had determined that “the Kincade fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E).” Accordingly, if PG&E Corporation or the Utility were determined to be liable for the 2019 Kincade fire, such liabilities could be significant and could exceed or be excluded from the amounts available under applicable insurance policies or the Wildfire Fund under AB 1054, which could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. As of December 31, 2020, PG&E Corporation and the Utility had recorded a loss of $625 million for the 2019 Kincade fire (before available insurance), which amount corresponds to the lower end of the range of reasonably estimable probable losses, but does not include all categories of potential damages. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to a 40% cap on the amount of such claim. As of December 31, 2020, the Utility had also recorded an insurance receivable for $430 million. (See “2019 Kincade Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information.)
•The Impact of the 2020 Zogg Fire. There have been numerous wildfires in the Utility’s service territory during the 2020 wildfire season. If the Utility were alleged or determined to be a cause of one or more of these wildfires, this allegation or determination could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. On October 9, 2020 Cal Fire informed the Utility that it had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the 2020 Zogg fire. The investigation is preliminary and Cal Fire has not issued a determination of cause, but if PG&E Corporation or the Utility were determined to be liable for the 2020 Zogg fire, such liabilities could be significant and could exceed or be excluded from the amounts available under applicable insurance policies or the Wildfire Fund under AB 1054, which could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. As of December 31, 2020, PG&E Corporation and the Utility had recorded a loss of $275 million for the 2020 Zogg fire (before available insurance), which amount corresponds to the lower end of the range of reasonably estimable probable losses, but does not include all categories of potential damages. As of December 31, 2020, the Utility had also recorded an insurance receivable for $219 million in connection with the 2020 Zogg fire. (For more information see “2020 Zogg Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
•The Impact of the COVID-19 Pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of COVID-19. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, the moratorium on service disconnections for residential and small business customers, the CPUC’s “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” and an observed reduction in non-residential electrical load. The Utility continues to monitor the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. This impact to liquidity may be partially offset by reductions in discretionary spending or potential regulatory impacts. As of December 31, 2020, PG&E Corporation and the Utility had access to approximately $2.8 billion of total liquidity comprised of approximately $261 million of Utility cash, $223 million of PG&E Corporation cash and $2.4 billion of availability under the Utility and PG&E Corporation credit facilities. Other potential impacts of COVID-19 on PG&E Corporation and the Utility include operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations, a reduction in revenue due to the cost of capital adjustment mechanism, the potential for higher credit spreads and borrowing costs and incremental financing needs. As discussed below under the heading “COVID-19 Pandemic Protections Memorandum Account,” the Utility has established a memorandum account for tracking costs related to the CPUC’s emergency authorization and order, which, as of December 31, 2020, was $84 million. The Utility intends to seek recovery of this balance in a future application, subject to CPUC reasonableness review. For more information on the impact of COVID-19 on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of the COVID-19 pandemic” in Item 1A Risk Factors in Part I.
PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. PG&E Corporation and the Utility continue to evaluate the overall impact of COVID-19 and their analysis is subject to change.
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•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the Safety Culture OII, the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, including the oversight of the Utility’s probation and the potential recommendations by the Monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California. Further, certain parties filed notices of appeal with respect to the Confirmation Order, including provisions related to the injunction contained in the Plan that channels certain pre-petition fire-related claims to trusts to be satisfied from the trusts’ assets. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.
•The Uncertainties in Connection with a Potential Enhanced Oversight and Enforcement Process. On November 24, 2020, the Utility received a letter (the “Letter”) from the President of the CPUC, related to the Utility’s vegetation and asset management activities and the CPUC’s Enhanced Oversight and Enforcement Process. If the Utility is placed into the Enhanced Oversight and Enforcement Process, it will be subject to additional reporting requirements, monitoring, and oversight by the CPUC.
For more information about the risks that could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors” in this 2020 Form 10-K. In addition, this annual 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. See the section entitled “Forward-Looking Statements” above for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are unable to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
RESULTS OF OPERATIONS
The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2020, 2019, and 2018. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.
PG&E Corporation
The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of net income (loss) available for common shareholders:
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Consolidated Total | $ | (1,318) | $ | (7,656) | $ | (6,851) | |||||||||||
| PG&E Corporation | (1,715) | (20) | (19) | ||||||||||||||
| Utility | $ | 397 | $ | (7,636) | $ | (6,832) | |||||||||||
PG&E Corporation’s net loss increased in 2020, as compared to 2019 and primarily consists of income taxes, interest expense on long-term debt, and reorganization items, net, including approximately $1.5 billion in expense related to the Backstop Commitment Premium Shares and Additional Backstop Premium Shares, which is not deductible for tax purposes.
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Utility
The table below shows certain items from the Utility’s Consolidated Statements of Income for 2020, 2019, and 2018. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings.
Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues and Costs: | Revenues and Costs: | Revenues and Costs: | |||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | That Impacted Earnings | That Did Not Impact Earnings | Total Utility | ||||||||||||||||||||||||||||||||||||||||||||
| Electric operating revenues | $ | 8,979 | $ | 4,879 | $ | 13,858 | $ | 8,634 | $ | 4,106 | $ | 12,740 | $ | 7,859 | $ | 4,854 | $ | 12,713 | |||||||||||||||||||||||||||||||||||
| Natural gas operating revenues | 3,460 | 1,151 | 4,611 | 3,259 | 1,130 | 4,389 | 3,046 | 1,001 | 4,047 | ||||||||||||||||||||||||||||||||||||||||||||
| Total operating revenues | 12,439 | 6,030 | 18,469 | 11,893 | 5,236 | 17,129 | 10,905 | 5,855 | 16,760 | ||||||||||||||||||||||||||||||||||||||||||||
| Cost of electricity | — | 3,116 | 3,116 | — | 3,095 | 3,095 | — | 3,828 | 3,828 | ||||||||||||||||||||||||||||||||||||||||||||
| Cost of natural gas | — | 782 | 782 | — | 734 | 734 | — | 671 | 671 | ||||||||||||||||||||||||||||||||||||||||||||
| Operating and maintenance | 6,399 | 2,308 | 8,707 | 7,167 | 1,583 | 8,750 | 5,475 | 1,678 | 7,153 | ||||||||||||||||||||||||||||||||||||||||||||
| Wildfire-related claims, net of insurance recoveries | 251 | — | 251 | 11,435 | — | 11,435 | 11,771 | — | 11,771 | ||||||||||||||||||||||||||||||||||||||||||||
| Wildfire fund expense | 413 | — | 413 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, amortization, and decommissioning | 3,469 | — | 3,469 | 3,233 | — | 3,233 | 3,036 | — | 3,036 | ||||||||||||||||||||||||||||||||||||||||||||
| Total operating expenses | 10,532 | 6,206 | 16,738 | 21,835 | 5,412 | 27,247 | 20,282 | 6,177 | 26,459 | ||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | 1,907 | (176) | 1,731 | (9,942) | (176) | (10,118) | (9,377) | (322) | (9,699) | ||||||||||||||||||||||||||||||||||||||||||||
| Interest income | 39 | — | 39 | 82 | — | 82 | 74 | — | 74 | ||||||||||||||||||||||||||||||||||||||||||||
| Interest expense | (1,111) | — | (1,111) | (912) | — | (912) | (914) | — | (914) | ||||||||||||||||||||||||||||||||||||||||||||
| Other income, net | 294 | 176 | 470 | 63 | 176 | 239 | 104 | 322 | 426 | ||||||||||||||||||||||||||||||||||||||||||||
| Reorganization items, net | (310) | — | (310) | (320) | — | (320) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | $ | 819 | $ | — | $ | 819 | $ | (11,029) | $ | — | $ | (11,029) | $ | (10,113) | $ | — | $ | (10,113) | |||||||||||||||||||||||||||||||||||
Income tax provision (benefit) (1) | 408 | (3,407) | (3,295) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | 411 | (7,622) | (6,818) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Preferred stock dividend requirement (1) | 14 | 14 | 14 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) Attributable to Common Stock | $ | 397 | $ | (7,636) | $ | (6,832) | |||||||||||||||||||||||||||||||||||||||||||||||
(1) These items impacted earnings.
Utility Revenues and Costs that Impacted Earnings
The following discussion presents the Utility’s operating results for 2020, 2019, and 2018, focusing on revenues and expenses that impacted earnings for these periods.
Operating Revenues
The Utility’s electric and natural gas operating revenues that impacted earnings increased $546 million, or 5%, in 2020 compared to 2019, primarily due to increased base revenues authorized in the 2020 GRC and 2019 GT&S rate cases, additional revenues recorded pursuant to the TO20 rate case, and CEMA interim rate relief.
The Utility’s electric and natural gas operating revenues that impacted earnings increased $988 million, or 9%, in 2019 compared to 2018, primarily due to increased revenues authorized in the 2017 GRC and 2019 GT&S rate cases, and revenues recorded pursuant to the TO20 rate case.
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Operating and Maintenance
The Utility’s operating and maintenance expenses that impacted earnings decreased $768 million, or 11%, in 2020 compared to 2019, primarily due to a reduction in accelerated transmission inspection and repair costs of approximately $460 million. Additionally, in 2019 the Utility recorded $398 million related to the Wildfires OII settlement and $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case in 2019, with no similar charges in 2020. These decreases were partially offset by an increase of $223 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) (the Utility amortized $298 million in deferred CEMA costs in 2020, compared to $75 million amortized in 2019). The Utility also experienced increased insurance premium costs in the year ended December 31, 2020, compared to 2019.
The Utility’s operating and maintenance expenses that impacted earnings increased $1,692 million, or 31%, in 2019 compared to 2018, primarily due to $773 million in costs related to enhanced and accelerated inspections and repairs of transmission and distribution assets, with no similar charges in the same period in 2018. Additionally, the Utility recorded $398 million in 2019 related to the Wildfires OII settlement, with no similar charge in the same period in 2018. Also, the Utility recorded $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case, with no similar charges in 2018.
Wildfire-related claims, net of insurance recoveries
Costs related to wildfires that impacted earnings decreased by $11.2 billion, or 98%, in 2020 compared to 2019. The Utility recognized pre-tax charges of $625 million related to the 2019 Kincade fire, partially offset by $430 million of probable insurance recoveries, and pre-tax charges of $275 million related to the 2020 Zogg fire, partially offset by $219 million of probable insurance recoveries in 2020. The Utility recognized charges of $11.4 billion in 2019, for wildfire-related claims primarily associated with the 2018 Camp fire and 2017 Northern California wildfires.
Costs related to wildfires that impacted earnings decreased by $336 million, or 3%, in 2019 compared to 2018. The Utility recognized charges of $11.4 billion and $11.8 billion in 2019 and 2018, respectively, for wildfire-related claims, net of probable insurance recoveries, primarily associated with the 2018 Camp fire and 2017 Northern California wildfires.
(See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
Wildfire fund expense
Wildfire fund expense that impacted earnings increased by $413 million, or 100%, in 2020 compared to 2019. In 2020, the Utility became eligible to participate in the Wildfire Fund and as a result recorded amortization and accretion expense related to the Wildfire Fund coverage received from the effective date of AB 1054 through December 31, 2020.
(See Notes 3 and 14 of the Notes to the Consolidated Financial Statements in Item 8.)
Depreciation, Amortization, and Decommissioning
The Utility’s depreciation, amortization, and decommissioning expenses increased by $236 million, or 7%, in 2020 compared to 2019, primarily due to capital additions and an increase in depreciation rates associated with the TO20 decision.
The Utility’s depreciation, amortization, and decommissioning expenses increased by $197 million, or 6%, in 2019 compared to 2018, primarily due to capital additions.
Interest Income
The Utility’s interest income that impacted earnings decreased by $43 million, or 52%, in 2020 compared to 2019. Interest income decreased by $8 million, or 11%, in 2019 compared to 2018. The Utility’s interest income is primarily affected by changes in regulatory balancing accounts and changes in interest rates.
Interest Expense
Interest expense that impacted earnings increased by $199 million, or 22%, in 2020 compared to 2019, primarily due to the issuance of new debt in 2020 in connection with the emergence from Chapter 11.
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The Utility’s interest expense decreased by $2 million, or 0%, in 2019 compared to 2018. Beginning January 29, 2019 in connection with the Chapter 11 Cases, the Utility ceased recording interest on outstanding pre-petition debt subject to compromise. In the fourth quarter of 2019, following the Bankruptcy Court’s December 30, 2019 memorandum decision in which it ruled that the holders of allowed unsecured claims are entitled to post-petition interest at the federal judgment rate of 2.59%, and pursuant to the terms of the Noteholder RSA, the Utility concluded that interest was probable of being an allowed claim and resumed recording interest on pre-petition debt subject to compromise.
Other Income, Net
Other income, net increased by $231 million, or 367%, in 2020 compared to 2019, primarily due to lower pension expense resulting from higher than expected return on plan assets.
The Utility’s other income, net decreased by $41 million, or 39%, in 2019 compared to 2018, primarily due to a decrease in AFUDC due to a decrease in equity ratio resulting from wildfire loss accruals.
Reorganization items, net
There was no material change to reorganization items, net that impacted earnings in 2020 compared to 2019.
Reorganization items, net increased by $320 million, or 100%, in 2019 compared to 2018, due to $370 million of expenses directly associated with the Utility’s Chapter 11 filing, partially offset by interest income of $50 million, with no corresponding charges in 2018.
Income Tax Provision (Benefit)
Income tax provision increased by $3.8 billion in 2020 compared to 2019, primarily due to a pre-tax loss in 2019 compared to pre-tax income in 2020. Additionally, there was a $619 million adjustment from the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020.
The Utility’s income tax benefit increased $112 million in 2019 compared to 2018, primarily due to higher pre-tax losses.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
| 2020 | 2019 | 2018 | |||||||||||||||
| Federal statutory income tax rate | 21.0 | % | 21.0 | % | 21.0 | % | |||||||||||
| Increase (decrease) in income tax rate resulting from: | |||||||||||||||||
State income tax (net of federal benefit) (1) | 19.1 | % | 7.5 | % | 7.9 | % | |||||||||||
Effect of regulatory treatment of fixed asset differences (2) | (44.9) | % | 2.8 | % | 3.6 | % | |||||||||||
| Tax credits | (1.7) | % | 0.1 | % | 0.1 | % | |||||||||||
Bankruptcy and emergence (3) | 54.1 | % | — | % | — | % | |||||||||||
Other, net (4) | 2.2 | % | (0.5) | % | — | % | |||||||||||
| Effective tax rate | 49.8 | % | 30.9 | % | 32.6 | % | |||||||||||
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) Includes an adjustment of the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust.
(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019.
Utility Revenues and Costs that did not Impact Earnings
Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs. See below for more information.
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Cost of Electricity
The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 10 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Cost of purchased power, net | $ | 2,854 | $ | 2,809 | $ | 3,531 | |||||||||||
| Fuel used in own generation facilities | 262 | 286 | 297 | ||||||||||||||
| Total cost of electricity | $ | 3,116 | $ | 3,095 | $ | 3,828 | |||||||||||
Cost of Natural Gas
The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 10 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Cost of natural gas sold | $ | 648 | $ | 622 | $ | 561 | |||||||||||
| Transportation cost of natural gas sold | 134 | 112 | 110 | ||||||||||||||
| Total cost of natural gas | $ | 782 | $ | 734 | $ | 671 | |||||||||||
Operating and Maintenance Expenses
The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred. If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.
Other Income, Net
The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.
LIQUIDITY AND FINANCIAL RESOURCES
Overview
As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date the financial statements were issued.
As of and subsequent to the Effective Date, the Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.
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PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility depends on the level of cash on hand, cash distributions received from the Utility, and PG&E Corporation’s access to the capital and credit markets.
In 2019, as a result of the initiation of the Chapter 11 Cases, each of Moody’s, Fitch, and S&P withdrew its credit ratings for PG&E Corporation and the Utility. As a result of PG&E Corporation’s and the Utility’s credit ratings ceasing to be rated at investment grade, the Utility was required to post collateral under certain of its commodity purchase agreements and certain other obligations. On June 15, 2020, Moody’s, Fitch, and S&P recommenced rating the Utility and PG&E Corporation.
PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may increase the cost and availability of short-term borrowing, including credit facilities and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies.
As a result of the outbreak of COVID-19, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could continue to be significantly affected. The Utility continues to evaluate the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist, including the moratorium on service disconnections for residential and small business customers and an observed reduction in non-residential electrical load. The Utility’s customer energy accounts receivable balances over 30 days outstanding as of December 31, 2020, were approximately $825 million, or $478 million higher as compared to the balances as of December 31, 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2021 and for as long as current COVID-19 circumstances persist. The reduction in cash collections from customers may be partially offset by reductions in discretionary spending or potential regulatory impacts.
The outbreak of COVID-19 and the resulting economic conditions and government orders have had and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have and will continue to impact the Utility for an indeterminate period of time. Although the Utility is seeking regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance that any relief is forthcoming or that, if any relief measures are implemented, the timing that any such relief would impact the Utility. On April 16, 2020, the CPUC approved a resolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the customer protections described within the resolution. On May 1, 2020, the Utility filed an advice letter with the CPUC, describing all reasonable and necessary actions to implement emergency customer protections through April 16, 2021, which was subsequently updated on June 2, 2020, and July 15, 2020, to modify and clarify the filing based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter. (See “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections” below for more information.)
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents consist of cash and short-term, highly liquid investments, with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.
Financial Resources
DIP Credit Agreement
In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, which received final approval from the Bankruptcy Court on March 27, 2019.
On July 1, 2020, the DIP Facilities (as defined in the DIP Credit Agreement) were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.
Equity Financings
On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. As of the termination date for this agreement, there were no issuances under this agreement.
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In connection with its emergence from Chapter 11, in July 2020, PG&E Corporation issued for gross proceeds of approximately $9.0 billion (i) 423.4 million shares of its common stock (the “Common Stock Offering”), (ii) 342.1 million shares of common stock to the PIPE Investors pursuant to the Investment Agreement, (iii) prepaid forward contracts between PG&E Corporation and the Backstop Parties dated as of June 19, 2020 (the “Forward Stock Purchase Agreements”) and (iv) 14.5 million of its equity units (the “Equity Units” and such offering the “Equity Unit Offering”).
In August 2020, PG&E Corporation issued (i) 1.45 million Equity Units to the Equity Units Underwriters upon their exercise of their over-allotment option to purchase up to 1.45 million additional Equity Units (such issuance, the “Additional Units Issuance”) and (ii) 42.3 million shares to the Backstop Parties pursuant to the Forward Stock Purchase Agreements (with the balance of the Forward Stock Purchase Agreements being redeemed with the cash proceeds of these additional Equity Units).
The prepaid forward stock purchase contract portion of the Equity Units issued in July and August 2020 represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided therein. The settlement date of the purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. Such gross proceeds were used to fund distributions under the Plan.
For the year ended December 31, 2020, PG&E Corporation made equity contributions to the Utility of $12.9 billion in cash and 478 million shares of PG&E Corporation common stock. Such shares were transferred to the Fire Victim Trust.
Debt Financings
Utility
On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and between the Escrow Agent and the Utility. On July 1, 2020, the net proceeds from the sale of the Mortgage Bonds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.
On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (collectively, the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt.
On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes.
The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first priority lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture.
On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated.
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On November 16, 2020, the Utility completed the sale of $1.45 billion aggregate principal amount of floating rate first mortgage bonds due November 15, 2021. Proceeds from the sale of the mortgage bonds were used for general corporate purposes, including the repayment of borrowings outstanding under the Receivables Securitization Program and under the Utility Revolving Credit Agreement.
For more information, see “Other Short-term Borrowings” and “Long-term Debt” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.
PG&E Corporation
On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “PG&E Corporation Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”). The PG&E Corporation Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The proceeds of the PG&E Corporation Term Loan were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the PG&E Corporation Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.
In accordance with the Term Loan Credit Agreement, PG&E Corporation is required to repay the principal amount outstanding on the PG&E Corporation Term Loan in an amount equal to $6.875 million on the last business day of each quarter.
On February 1, 2021, PG&E Corporation entered into a repricing amendment with the lenders under the Term Loan Credit Agreement pursuant to which, among other things, the applicable interest rate was reduced.
Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 and (ii) $1 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (collectively, the “Notes”). The proceeds of the Notes were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and amount the Escrow Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan.
On the Effective Date, PG&E Corporation repaid and terminated $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.
For more information, see “Long-Term Debt” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.
Credit Facilities
Utility
On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM., and Citibank, N.A. as co-administrative agents and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has tenor of three years, subject to two one-year extension options. The proceeds from the borrowings under the Utility Revolving Credit Agreement were used to fund, in part, transactions contemplated under the Plan and are intended to finance working capital needs, capital expenditures and other general corporate purposes of the Utility and its subsidiaries.
In addition, on July 1, 2020, the Utility obtained a $3 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent, and the other lenders from time to time party thereto. The facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the Utility 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The proceeds from the loans under the Utility Term Loan Credit Agreement were used to fund, in part, transactions contemplated under the Plan.
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At December 31, 2020, the Utility had $3.0 billion of debt outstanding under the Term Loan Credit Agreement and had $1.9 billion available under the $3.5 billion Utility Revolving Credit Agreement.
For more information, see “Credit Facilities” in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.
PG&E Corporation
On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of PG&E Corporation. The proceeds from loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.
On the Effective Date, PG&E Corporation repaid and terminated $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent.
At December 31, 2020, PG&E Corporation did not have any borrowings outstanding under the Corporation Revolving Credit Agreement.
For more information, see “Credit Facilities” in Note 5 to the Consolidated Financial Statements in Item 8.
Receivables Securitization Program
On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility’s accounts receivable to the SPV, a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1 billion outstanding at any time.
The loans under the Receivables Securitization Program bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate. The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events.
The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable.
In general, the proceeds from the sale of the accounts receivable are used by the SPV to pay the purchase price for accounts receivables it acquires from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses.
Although the SPV is a wholly owned consolidated subsidiary of the Utility, the SPV is legally separate from the Utility. The assets of the SPV (including the accounts receivable) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program is accounted for as a secured financing. The pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets.
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Dividends
On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.
On April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s WMP.
On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.
In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.
Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.
Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of December 31, 2020, it is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.
Utility Cash Flows
The Utility’s cash flows were as follows:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Net cash provided by (used in) operating activities | $ | (19,047) | $ | 4,810 | $ | 4,704 | |||||||||||
| Net cash used in investing activities | (7,748) | (6,378) | (6,564) | ||||||||||||||
| Net cash provided by financing activities | 26,070 | 1,395 | 2,708 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | $ | (725) | $ | (173) | $ | 848 | |||||||||||
Operating Activities
The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During 2020, net cash provided by operating activities decreased by $23.9 billion compared to 2019. This decrease was primarily due to the payment of $18.8 billion in satisfaction of pre-petition wildfire-related claims (including claims associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire), and the initial, first and second annual contributions made to the Wildfire Fund of $5.2 billion, with no similar payments made in 2019.
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During 2019, net cash provided by operating activities increased by $106 million compared to 2018. This increase was due to a decrease in interest paid from $773 million to $7 million as a result of the automatic stay as of the Petition Date. Additionally, income taxes paid decreased from $59 million in 2018 to zero in 2019. These decreases in amounts paid were offset by an increase in amounts paid for reorganization items, and enhanced and accelerated inspections and repairs of transmission and distribution assets in 2019, with no similar payments in 2018, partially offset by additional amounts not paid due to the automatic stay as of the Petition Date.
Future cash flow from operating activities will be affected by various factors, including:
•the timing and amount of costs in connection with the 2019 Kincade fire;
•the timing and amount of costs in connection with the 2020 Zogg fire;
•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Enforcement Matters” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below for more information);
•the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions and the ability of the Utility to recover from customers any losses incurred in connection with COVID-19, as well as the impact of COVID-19 on the availability or cost of financing;
•the timing and amounts of annual contributions to the Wildfire Fund and if necessary, the availability of funds to pay eligible claims for liabilities arising from future wildfires;
•the timing and amount of substantially increasing costs in connection with the 2019 and 2020-2022 WMPs that are not currently being recovered in rates (see “Regulatory Matters” below for more information);
•the timing and amount of premium payments related to wildfire insurance (see “Insurance Coverage” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information);
•the timing of and amount of the gain to be returned to customers from the sale of the SFGO; and
•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.
Investing Activities
Net cash used in investing activities increased by $1.4 billion during 2020 as compared to 2019 partially due to the payment of pre-petition vendor payables for capital expenditures as a result of emerging from Chapter 11. Net cash used in investing activities decreased by $186 million during 2019 as compared to 2018 primarily due to a decrease in cash paid for capital expenditures as a result of the automatic stay as of the Petition Date. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur between $7.5 billion and $8.3 billion in capital expenditures in 2021. Additionally, future cash flows from investing activities will be impacted by the timing of and amount received from the proposed sale of the Utility’s SFGO.
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Financing Activities
During 2020, net cash provided by financing activities increased by $24.7 billion as compared to 2019. This increase was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13.0 billion, and due to the Utility receiving $10.4 billion in proceeds from the issuance of short-term and long-term first mortgage bonds, with no similar activity in 2019. Additionally, the Utility had net borrowings of $4.6 billion under its credit facilities during the year ended December 31, 2020, with no similar activity in 2019 due to the Utility entering into the facilities in 2020. These increases were partially offset by net repayments of $1.5 billion on the DIP facilities in 2020, as compared to net borrowings of $1.5 billion on the DIP facilities in 2019.
During 2019, net cash provided by financing activities decreased by $1.3 billion as compared to 2018. This decrease was primarily due to $2.9 billion of net borrowings under revolving credit facilities in 2018, partially offset by $1.5 billion of net borrowings under the DIP initial term loan facility in 2019.
Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments.
CONTRACTUAL COMMITMENTS
The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2020:
| Payment due by period | |||||||||||||||||||||||||||||
| (in millions) | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | Total | ||||||||||||||||||||||||
| Utility | |||||||||||||||||||||||||||||
Long-term debt (1) | $ | 4,043 | $ | 7,778 | $ | 4,209 | $ | 35,895 | $ | 51,925 | |||||||||||||||||||
Purchase obligations (2) | |||||||||||||||||||||||||||||
| Power purchase agreements | 2,917 | 4,896 | 4,198 | 21,657 | 33,668 | ||||||||||||||||||||||||
| Natural gas supply, transportation, and storage | 466 | 349 | 302 | 184 | 1,301 | ||||||||||||||||||||||||
| Nuclear fuel agreements | 64 | 103 | 47 | — | 214 | ||||||||||||||||||||||||
Pension and other benefits (3) | 342 | 684 | 684 | 342 | 2,052 | ||||||||||||||||||||||||
Operating leases (2) | 42 | 80 | 129 | 3,019 | 3,270 | ||||||||||||||||||||||||
Preferred dividends (4) | 14 | 28 | 28 | — | 70 | ||||||||||||||||||||||||
| PG&E Corporation | |||||||||||||||||||||||||||||
Long-term debt (1) | — | — | 2,901 | 2,000 | 4,901 | ||||||||||||||||||||||||
| Total Contractual Commitments | $ | 7,888 | $ | 13,918 | $ | 12,498 | $ | 63,097 | $ | 97,401 | |||||||||||||||||||
(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2020 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. (See Note 5 of the Notes to the Consolidated Financial Statements in Item 8.)
(2) See “Purchase Commitments” and “Other Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
(3) See Note 12 of the Notes to the Consolidated Financial Statements in Item 8. Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the amount shown in the column entitled “more than 5 years” represents only 1 year of contributions for the Utility’s pension and other benefit plans.
(4) Beginning with the three-month period ending January 31, 2018, quarterly cash dividends on the Utility’s preferred stock were suspended. While the timing of cumulative dividend payments is uncertain, it is assumed for the table above to be payable within a fixed period of five years based on historical performance. (See Note 7 of the Notes to the Consolidated Financial Statements in Item 8.)
The contractual commitments table above excludes potential payments associated with unrecognized tax positions. Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amounts and periods of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed in Note 9 of the Notes to the Consolidated Financial Statements in Item 8.
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Except as otherwise set forth in the Plan and the Confirmation Order, all executory contracts and unexpired leases were assumed by PG&E Corporation or the Utility, as applicable, on the Effective Date. Accordingly, any description of an executory contract or unexpired lease with PG&E Corporation or the Utility in this Annual Report on Form 10-K, including where applicable a quantification of the obligations under any such executory contract or unexpired lease, is qualified by any overriding assumption or rejection rights PG&E Corporation or the Utility, as applicable, has under the Bankruptcy Code, the Plan, and the Confirmation Order. Further, nothing herein is or shall be deemed to be an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and PG&E Corporation and the Utility expressly reserve all of their rights with respect thereto.
Off-Balance Sheet Arrangements
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
ENFORCEMENT AND LITIGATION MATTERS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8. that are incorporated by reference herein. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
U.S. District Court Matters and Probation
On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.
The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. 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 to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.
On August 7, 2020, after a number of filings involving different parties, the court entered an order adopting the new conditions jointly proposed by the Utility, the Monitor, and the Department of Justice on June 24, 2020. Among other things, these conditions require the Utility to staff an in-house vegetation inspection manager and approximately 30 additional field inspectors to oversee vegetation management work. Further, the Utility is required to implement a program to assess the age and expected useful life of certain electrical components in high fire-threat areas, incorporate this information into its risk-based asset management programs, and provide monthly progress reports to the Monitor. The Utility must also hire additional inspectors to oversee inspections of its transmission assets and implement a 90-day replacement requirement for cold end hardware in high fire-threat areas with an observed material loss approaching 50%.
On December 29, 2020, the court entered an order requiring the Utility to show cause as to why additional proposed conditions of probation should not be added. The proposed conditions would require the Utility to, when determining which distribution lines to de-energize during a PSPS event: (i) take into account the extent to which vegetation bordering those lines is not in compliance with certain requirements, and (ii) to the extent that information shows that such vegetation presents a safety hazard in the event of a windstorm, make a specific determination with respect to that distribution line and de-energize it unless the Utility finds in writing that there are specific reasons to believe that no safety issues exist. The Utility filed its response on January 20, 2021, proposing supplemental language to clarify and specify how the Utility will implement the new conditions proposed by the court. A hearing on the matter was held on February 3, 2021. On February 4, 2021, the court entered an order indicating that, if certain alterations were made, the court may be willing to accept the Utility’s proposed modified conditions in lieu of the conditions proposed in the court’s December 29, 2020 order. All parties and amici responded to the order on February 19, 2021 and any replies must be submitted by February 26, 2021. A hearing is scheduled for March 9, 2021.
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On February 4, 2021, the court entered an order requiring the Utility to show cause as to why the additional proposed conditions of probation suggested by amici in a January 27, 2021 filing should not be added. The proposed conditions would require the Utility to: (i) hire a chief data operations officer with the responsibility to review the Utility’s information management and record-keeping systems and manage the relationship to operations, including vegetation management work and PSPS; (ii) initiate steps to prevent data falsification or omission; (iii) propose a plan to mark trees in tier 2 and tier 3 high wildfire danger zones for removal and track the status of the tree removal process for vegetation management; and (iv) propose steps to improve its information management and records-keeping process to improve information integrity, inform analysis, and inform and enhance daily operations including PSPS. The Utility’s, the Monitor’s, and the United States’ responses are due by March 3, 2021, and any reply by amici is due by March 10, 2021.
On February 18, 2021, the court issued an order requiring the Utility to show cause as to why an additional proposed condition of probation, which would require the Utility to “identify and remove any tree or portion thereof leaning toward any distribution line if it may contact the line from the side or fall on the line and must do so regardless of the health of the tree[,]” should not be added. The Utility’s response is due by March 4, 2021, any response by the United States and/or amici is due by March 11, 2021, and the Utility’s reply is due by March 17, 2021. A hearing on the matter is scheduled for March 23, 2021.
In the course of 2020 and 2021, the court entered numerous other orders, including in connection with the Utility’s vegetation management, the Utility’s PSPS program, the 2018 Camp fire, the 2019 Kincade fire, and the 2020 Zogg fire.
The Utility expects to receive additional orders from the court in the future.
Order Instituting an Investigation into PG&E Corporation’s and the Utility’s Safety Culture
On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The SED engaged a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment, and subsequently, to report on the implementation by the Utility of the consultant’s recommendations.
On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’s rate of return or return on equity to safety performance metrics. Opening comments on the ruling were filed on July 19, 2019 and reply comments were filed on August 2, 2019.
On September 4, 2020, the ALJ issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture, and to address any relevant issues that arise, with the CPUC’s consultant NorthStar Consulting Group, Inc. continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.
REGULATORY MATTERS
The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
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Rate Cases
2020 Cost of Capital Proceeding
On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020, as compared to 12% requested by the Utility. The Utility’s annual cost of capital adjustment mechanism, which allows for changes in the Utility’s authorized ROE and cost of debt, also remains unchanged. In any year in which the difference between the average Moody’s utility bond rates, as measured in the 12-month period from October through September, and 4.5% (the benchmark) exceeds 100 basis points, the Utility’s ROE will be adjusted by one-half of such difference, and the cost of debt will be trued up to the most recent recorded cost of debt. The Utility can initiate this adjustment mechanism by filing an advice letter on or before October 15, to become effective on January 1 of the next year. The mechanism did not trigger in September 2020; however, as of December 31, 2020, the index is more than 100 basis points below the 4.5% benchmark. If the mechanism triggers in October 2021, then for 2022 the ROE and the cost of debt will be adjusted accordingly. The decision maintains the common equity component of the Utility’s capital structure at 52%, as requested by the Utility, and reduces its preferred stock component from 1% to 0.5%, also as requested by the Utility. The decision also approves the cost of debt requested by the Utility.
On May 28, 2020, the CPUC issued a decision in the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization that directed the Utility to submit an Advice Letter to update its authorized cost of debt within 30 days of the Effective Date of the Plan. On July 22, 2020, the Utility submitted an Advice Letter requesting to update the authorized cost of long-term debt to implement the interest cost savings resulting from the Utility’s exit financing. On August 20, 2020, the CPUC approved the Utility’s request to update the authorized cost of long-term debt from 5.16%, as authorized in December 2019, to 4.17% effective July 1, 2020.
2017 General Rate Case
As previously disclosed, on September 13, 2019 the Utility submitted an advice letter containing a revised computation of its revenue requirement due to the effects of the Tax Act, which indicated a $282 million net reduction to the 2018 revenue requirement and a $291 million net reduction to the 2019 revenue requirement. The revised gas revenue requirements increased by $21 million and $11 million for years 2018 and 2019, respectively, and the revised electric revenue requirements decreased by $304 million and $302 million for years 2018 and 2019, respectively. On October 17, 2019, the CPUC approved the Utility’s advice letter. The Utility incorporated the gas revenue requirement increases into rates through its Annual Gas True-up advice letter beginning on January 1, 2020 and amortized over 12 months. The Utility incorporated the electric revenue requirement reductions into rates through its Annual Electric True-up advice letter beginning on May 1, 2020. The Utility incorporated the total $606 million electric revenue requirement reduction as follows: (i) $175 million related to electric generation was amortized over 12 months, (ii) the 2018 revenue requirement reduction of $215 million related to electric distribution was amortized over 10 months, and (iii) the 2019 revenue requirement reduction of $216 million related to electric distribution was included in the Utility’s 2021 Annual Electric True-up beginning on January 1, 2021, to be amortized over 12 months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.
2020 General Rate Case
On December 3, 2020, the CPUC approved the final decision for the Utility’s 2020 GRC.
The final decision adopted most of the provisions in the settlement agreement that the Utility, together with the settling parties, jointly submitted to the CPUC on December 20, 2019 (the “settlement agreement”).
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Revenue Requirements and Attrition Year Revenues
The final decision approved a 2020 authorized revenue requirement of $9.102 billion, an increase of $585 million over the 2019 authorized revenue requirement, effective January 1, 2020, as provided in the settlement agreement. The CPUC also approved the revenue requirements for 2021 and 2022 included in the settlement agreement as follows: an additional increase of $316 million in 2021 over the authorized 2020 revenue requirement, or a 3.5% increase, and an additional increase of $364 million in 2022, or a 3.9% increase. The revenue requirements will be further modified by advice letters to reflect an updated cost of debt, to remove certain customer deposits balances, and to return to customers the excess accumulated deferred income taxes that were created by the passage of the 2017 Tax Act. Subject to the CPUC approving the advice letters, the effective dates for the 2021 and 2022 attrition year revenue requirements will be March 1, 2021, and January 1, 2022, respectively. The 2021 attrition year revenue requirement will not be implemented in rates until March 1, 2021. The Utility is authorized to collect in rates the difference between the revenue requirement in effect and the 2020 GRC decision-authorized revenue requirement for the period of January 1, 2020 to February 28, 2021 over the period of March 1, 2021 through December 31, 2022.
The final decision also approves, among other things, the settlement agreement provision that allows the Utility to recover the annual cost of excess liability insurance for coverage of up to $1.4 billion. An advice letter is required for recovery of excess liability insurance costs for coverage exceeding $1.4 billion. The final decision also approved wildfire mitigation capital expenditures in the Community Wildfire Safety Program of $603 million in 2020, $931 million in 2021 and $1.15 billion in 2022, as provided in the settlement agreement. In addition, the final decision requires a reasonableness review and recovery of WMBA costs or unit costs for system hardening in excess of 115% of the adopted amounts and VMBA costs in excess of 120% of the adopted amounts through an application.
The following table shows the revenue requirement amounts approved in the final decision based on line of business and cost category as well as the differences between the 2019 authorized revenue requirements and the amounts approved in the final decision:
| (in millions) Lines of Business: | Amounts Approved in Final Decision | Increase/ (Decrease) 2019 vs. Final Decision | |||||||||
| Electric distribution | $ | 4,800 | $ | 436 | |||||||
| Gas distribution | 2,013 | 51 | |||||||||
| Electric generation | 2,289 | 98 | |||||||||
| Total revenue requirements | $ | 9,102 | $ | 585 | |||||||
| Cost Category: | |||||||||||
| Operations and maintenance | $ | 2,073 | $ | 128 | |||||||
| Customer services | 277 | (61) | |||||||||
| Administrative and general | 1,203 | 250 | |||||||||
| Less: Revenue credits | (195) | (42) | |||||||||
| Franchise fees, taxes other than income, and other adjustments | 214 | 32 | |||||||||
| Depreciation (including costs of asset removal), return, and income taxes | 5,530 | 278 | |||||||||
| Total revenue requirements | $ | 9,102 | $ | 585 | |||||||
Rate Base and Capital Additions
The CPUC also adopted the rate base amounts proposed in the settlement agreement: the 2019 weighted-average rate base of $27.7 billion was increased by $1.7 billion, effective January 1, 2020, to $29.5 billion, or a 6.2% increase; rate base of $31.0 billion in 2021, or a 5.4% increase; and $33.0 billion in 2022, or a 6.3% increase. Consistent with AB 1054, the adopted rate base amounts include $140 million for August to December 2019, $603 million for 2020, $931 million for 2021 and $1.15 billion for 2022, for a total of $2.83 billion in forecast capital spend without an equity return.
Over the 2020-2022 GRC period, the decision provides average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution and electric generation infrastructure.
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Consistent with the Utility’s GRC application, the settlement agreement did not propose funding for claims resulting from the 2017 Northern California wildfires or the 2018 Camp fire. Also, the Utility did not seek recovery of compensation for PG&E Corporation’s and the Utility’s officers.
2023 General Rate Case
In accordance with a January 16, 2020 CPUC decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, the Utility is required to file with the CPUC on June 30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years. The Utility expects to file the 2023 GRC by June 30, 2021.
On June 30, 2020, the Utility filed the 2020 RAMP Report in advance of its 2023 GRC filing. On November 25, 2020, the CPUC’s SPD released its evaluation of the Utility’s 2020 RAMP Report. The SPD found that “[t]he 2020 RAMP showed marked improvements in risk modeling rigor, data quality, and transparency over previous rate cases,” but cautioned that the Utility’s “track record calls for continued improvements by PG&E and continued rigorous oversight by the Commission.” The SPD held a workshop on its evaluation of the Utility’s RAMP on December 8, 2020, and opening and reply comments were submitted on January 15, 2021 and January 29, 2021, respectively.
2015 Gas Transmission and Storage Rate Case
As previously disclosed, in its final decisions in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount forecast to be recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The audit report was released June 2, 2020 and did not recommend any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery, through a separate application, of those costs not recommended for disallowance by the audit. On July 31, 2020, the Utility filed an application seeking recovery of $373.3 million in revenue associated with $512 million of recorded capital expenditures. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.
On November 10, 2020, the Utility filed a motion seeking approximately $100 million in interim rates, assuming the CPUC reaches a final decision in this matter in late 2021 or early 2022. The CPUC has not yet ruled upon the Utility’s motion.
The Utility is unable to predict the timing and outcome of this application.
As previously disclosed, as a result of the Tax Act, on October 17, 2019, the CPUC approved the Utility’s advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the 2018 revenue requirement. The Utility incorporated the revenue requirement reduction into rates through its Annual Gas True-up advice letter beginning January 1, 2020 and amortized over 12 months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.
2019 Gas Transmission and Storage Rate Case
As previously disclosed, on September 12, 2019, the CPUC voted out the final decision in the 2019 GT&S rate case of the Utility. By approving the decision, the CPUC adopted a 2019 revenue requirement of $1.332 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $31 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The CPUC also adopted revenue requirements of $1.432 billion for 2020, $1.516 billion for 2021, and $1.580 billion for 2022, compared to the Utility’s request of $1.595 billion for 2020, $1.693 billion for 2021, and $1.679 billion for 2022.
As previously disclosed, on October 23, 2019, the Utility filed an application with the CPUC requesting the rehearing of the final decision. Specifically, issues identified by the Utility include the adopted disallowance associated with vintage pipe replacement, reduction in the Utility’s expense forecast for in-line inspections, and establishment of a memo account for Internal Corrosion Direct Assessment. The Utility cannot predict the timing and outcome of this matter.
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As previously disclosed, 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 be required to combine the GRC and GT&S rate cases starting with the 2023 GRC. In accordance with the decision, on June 30, 2021, the Utility is required to file with the CPUC a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.
Transmission Owner Rate Cases
Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)
As previously disclosed, on January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of the FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50-basis point ROE incentive adder for its continued participation in the CAISO. If the FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Those rate case decisions were remanded to the FERC for further proceedings consistent with the Court of Appeals’ opinion.
On July 18, 2019, the FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order.
On March 17, 2020, the FERC issued its order denying the requests for rehearing. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Utility submitted briefing on November 12, 2020 and the briefing on the appeal was completed on December 2, 2020. The Utility is unable to predict the timing and outcome of this proceeding.
Transmission Owner Rate Case for 2017 (the “TO18” rate case)
As previously disclosed, on July 29, 2016, the Utility filed its TO18 rate case with the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility sought a ROE of 10.9%, which included an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects.
Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.9%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility’s rate base and revenue requirement. Finally, the ALJ rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s initial decision.
On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, which refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs and testimony were filed on December 14, 2020 and responses were filed on February 12, 2021. The Utility’s initial brief requested a ROE of 13.29%. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the order reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Aside from the ultimate outcome of the common plant allocation and ROE methodology, which is subject to further briefing, the FERC’s October 15, 2020 order is not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s current formula rate, described below under the TO20 rate case.
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On November 16, 2020, the Utility submitted a request for rehearing of certain rulings in the FERC’s October 15, 2020 order. The Utility requested in its application, among other things, that the FERC allow the Utility to demonstrate that the common, general and intangible plant costs actually occurred. Two intervenors in the case also filed for rehearing on net salvage value and the applicability of the Tax Act to the Utility’s rates. On December 17, 2020, the FERC denied all the pending requests for rehearing. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties.
The Utility is unable to predict the timing and outcome of this proceeding.
Transmission Owner Rate Case for 2018 (the “TO19” rate case)
As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case with the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 was $6.9 billion. The Utility sought a ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion.
Also, as previously disclosed, on September 21, 2018, the Utility filed an all-party settlement with the FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. Additionally, if the Court of Appeals were to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. See Transmission Owner Rate Cases for 2015 and 2016 above for a discussion of the incentive adder. On December 20, 2018, the FERC issued an order approving the all-party settlement.
Transmission Owner Rate Case for 2019 (the “TO20” rate case)
As previously disclosed, on October 1, 2018, the Utility filed its TO20 rate case with the FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the Effective Date for rate changes. The FERC also ordered that the hearings be held in abeyance pending settlement discussions among the parties.
The formula rate replaces the “stated rate” methodology that the Utility used in its previous TO rate case filings. The formula rate methodology still includes an authorized revenue requirement and rate base for a given year, but it also provides for an annual update of the following year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements are updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate are either collected from or refunded to customers.
On March 31, 2020, the Utility filed a partial settlement with the FERC that resolves issues regarding the inputs, and methods used in the formula rate consistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to review transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in TO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base with the CAISO register data base; and requires the Utility to seek the FERC’s authorization before recovering claims related to the 2017 Northern California wildfires and the 2018 Camp fire. The partial settlement was approved by the FERC on August 17, 2020.
On October 15, 2020, the Utility filed a settlement with the FERC resolving all of the remaining issues in the Formula Rate Proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement establishes an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024. The settlement also requires the Utility to concurrently file a motion for interim rates requesting that the settlement rates go into effect on January 1, 2021 while approval of the settlement is pending at the FERC. Also as part of the settlement, the Utility made supplemental filings to revise its request in two FERC dockets on October 15, 2020 addressing the calculation of the Utility’s AFUDC to reflect the terms of the settlement.
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On December 30, 2020, the FERC approved the October 15, 2020 settlement without modifications. Also, on December 30, 2020, the FERC approved the two AFUDC dockets addressing the calculation of the Utility’s AFUDC calculation without modifications.
Nuclear Decommissioning Cost Triennial Proceeding
While the Utility expects active decommissioning to begin soon after expiration of the current operating licenses, the Utility expects that the decommissioning of Diablo Canyon will take many years. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory, site restoration, and remediation requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.
As previously disclosed, on December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion to decommission the Diablo Canyon facilities.
Also, as previously disclosed, on January 10, 2020, the settlement agreement that the parties had reached in this proceeding was filed with the CPUC, along with a joint motion for adoption of the settlement agreement.
Under the proposed settlement agreement, the Utility would collect annual revenue requirements of $112.5 million and $3.9 million for the funding of the Diablo Canyon non-qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, under the proposed settlement agreement, the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to date would be deemed reasonable.
On February 22, 2021, the CPUC extended the statutory deadline to resolve this proceeding to September 13, 2021. A proposed decision is expected in the fourth quarter of 2021.
Application for Wildfire Mitigation and Catastrophic Events Interim Rates
On February 7, 2020, the Utility filed an interim relief application seeking $899 million in interim rates related to certain electric distribution costs recorded in the following memorandum accounts: WMPMA, FRMMA, FHPMA, and CEMA. The costs pertain mainly to the years 2017-2019. The application addresses costs recorded in: (i) the WMPMA and FRMMA to comply with the 2019 WMP and other wildfire mitigation costs not otherwise recoverable through rates, (ii) the FHPMA to comply with various fire safety rulemakings through 2019, and (iii) the CEMA for responding to, and restoring customer service after, certain storms and fires occurring in 2017-2019.
The Utility submitted a request on March 23, 2020, to reduce the interim rate relief by $8.4 million. This reduction, which reduces the requested rate relief to $891 million, relates to the capital cost reduction required by AB 1054.
On October 22, 2020, the CPUC voted out its final decision that approved interim relief in the amount of $447 million. The Utility will recover these costs over a 17-month period beginning in January 2021.
Wildfire Mitigation and Catastrophic Events Costs Recovery Application
On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities (the “WMCE application”). The recorded expenditures, which exclude amounts disallowed as a result of the CPUC’s decision in the OII into the 2017 Northern California Wildfires and the 2018 Camp fire, consist of $1.18 billion in expense and $801 million in capital expenditures, resulting in a revenue requirement of approximately $1.28 billion.
The costs addressed in the WMCE application cover activities mainly during the years 2017 to 2019 and are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflect work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility’s requested revenue includes amounts for the FHPMA of $293 million, the FRMMA and the WMPMA of $740 million, and the CEMA of $251 million. The requested revenue for CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events, including the 2017 Tubbs fire.
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In its application, the Utility proposed the following ratemaking scenario: given the CPUC approval of $447 million in interim rate relief which includes interest, the Utility proposed to recover the remaining $868 million revenue requirement, including interest, over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review.
On December 23, 2020, the assigned commissioner issued a scoping memo and ruling for the proceeding, which calls for a proposed decision to be issued in September 2021.
The Utility is unable to predict the outcome of this application. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs included in this application.
For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see “Wildfire Mitigation Memorandum and Balancing Accounts” and “Catastrophic Event Memorandum Accounts and Applications” below.
Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account
On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA.
On April 2, 2020, the CPUC held a prehearing conference in this matter. On January 12, 2021, the CPUC issued a scoping memo establishing the scope and schedule for the proceeding. As amended by subsequent rulings, the schedule calls for a final decision in August 2021. The Utility cannot predict the outcome of this proceeding.
Catastrophic Event Memorandum Accounts and Applications
The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. In the 2020 GRC Decision, the CPUC required the Utility to track these costs in the VMBA beginning January 1, 2020. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
2019 CEMA Application
On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with 13 catastrophic events that included 12 wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.
On August 31, 2020 the Utility, TURN and the PAO filed a joint motion seeking approval and adoption of a settlement agreement reached between the settling parties. The settlement agreement proposes a total revenue requirement of $136.7 million consisting of an expense revenue requirement of $112 million and a capital revenue requirement for 2017 through 2022 of $24.7 million.
On November 19, 2020, the CPUC issued a final decision adopting the settlement agreement.
2018 CEMA Application
On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation.
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On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs as requested by the Utility at that time, compared to $588 million requested by the Utility. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a revised application, revised testimony and revised workpapers, reflecting a new revenue requirement request of $669 million, pursuant to a CPUC ruling allowing these changes.
The 2018 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.
On March 9, 2020, the CPUC issued a modified scoping memo and ruling. On May 4, 2020, the Utility filed a revised application, which included 2019 tree mortality costs, reflecting a new revenue requirement request of $757 million, and the costs of an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.
On January 8, 2021, the Utility filed a revised application updating the revenue requirement to include an additional $5.6 million of tree mortality costs and the cost of hiring an independent auditor.
The Utility is unable to predict the timing and outcome of this proceeding.
Wildfire Mitigation Memorandum and Balancing Accounts
Fire Hazard Prevention Memorandum Account
The CPUC allows utilities to track and record costs associated with implementing regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. The Utility tracked such costs in the FHPMA through the end of 2019.
On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agrees, among other things, to not seek recovery of $36 million of wildfire-related expenses recorded in the FHPMA. For more information on the settlement agreement, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
Other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire, the Utility believes such costs are recoverable, but rate recovery requires CPUC reasonableness review.
The Utility requested recovery of costs recorded in the FHPMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application described above. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.)
The amount reflected in this memorandum account as of December 31, 2020 was $258 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Fire Risk Mitigation Memorandum Account
On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized to capture mitigation costs of activities not included in a CPUC approved WMP. The Utility has proposed that the FRMMA continue after the approval of its 2019 WMP to record costs of wildfire mitigation activities that were beyond the initial identified scope of work or are incurred prior to approval of the WMP in which they are proposed. The FRMMA includes costs associated with the 2019 WMP from the period January 1, 2019 through June 4, 2019, as well as subsequent wildfire mitigation costs not included in the WMPMA, discussed below. Recovery of costs are subject to CPUC review and approval. The Utility will continue to use the FRMMA for new programs or expanded scope of existing programs before the WMP is approved.
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On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agreed, among other things, not to seek recovery of $236 million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For more information on the settlement agreement, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
The Utility requested recovery of costs recorded in the FRMMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP recorded in the FRMMA.
The amount reflected in this memorandum account as of December 31, 2020 was $99 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Wildfire Mitigation Balancing Account
In the 2020 GRC Decision, the CPUC authorized the Utility to establish the WMBA effective January 1, 2020, to track and record actual expenses incurred and the capital revenue requirement associated with actual capital additions incurred compared to the total adopted revenue requirements for specified wildfire mitigation activities, for the period beginning January 1, 2020. The WMBA is a two-way balancing account, which allows the Utility to seek cost recovery for amounts exceeding the approved revenue requirement, subject to a demonstration of reasonableness. The Utility is required to submit an application to the CPUC to recover the costs of program expenditures exceeding 115% of the adopted amounts or if the average overhead or underground system hardening per mile unit costs exceed specified unit costs by 115%.
The amount reflected in this balancing account as of December 31, 2020 was $183 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Wildfire Mitigation Plan Memorandum Account
As previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Mitigation Plan Memorandum Account) effective May 30, 2019. The WMPMA is required to be established upon approval of a utility’s WMP to track costs incurred to implement the Utility’s WMPs. The CPUC approved the memorandum account on August 8, 2019, so the Utility has recorded costs incurred in implementing the WMPs, as of June 5, 2019, the effective date of the WMPMA.
The Utility requested recovery of costs recorded in the WMPMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP and the 2020 WMP recorded in the WMPMA.
The amount reflected in this memorandum account as of December 31, 2020 was $551 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Vegetation Management Balancing Account
The VMBA was approved by the CPUC in the Utility’s 1999 GRC as a one-way balancing account mechanism to recover the costs of routine vegetation management expenditures, in an amount not to exceed the approved revenue requirement. In the 2020 GRC Decision, the CPUC authorized the Utility to modify the VMBA as a two-way balancing account, which allows the Utility to seek recovery of expenditures incurred above the revenue requirement, subject to a demonstration of reasonableness, for the period beginning January 1, 2020. The account was further modified to include the Utility’s new enhanced vegetation management program and additional vegetation management costs currently recorded in the CEMA for which there is no approved revenue requirement. The Utility is required to submit an application to the CPUC to recover the costs of program expenditures exceeding 120% of the adopted amounts. If the Utility’s expenditures are less than the approved revenue requirement, the Utility will return any over collection to customers through an advice letter.
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The amount reflected in this balancing account as of December 31, 2020 was $707 million. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Risk Transfer Balancing Account
In the 2020 GRC Decision, the CPUC authorized the Utility to establish the RTBA effective January 1, 2020, to track and record actual expenses incurred compared to the adopted revenue requirements for the GRC portion of excess liability insurance costs, inclusive of all financial risk transfer mechanisms (insurance, reinsurance, catastrophe bonds, captives), and related costs (such as broker fees and excise taxes). The Utility would seek recovery of any risk transfer costs associated with coverage above $1.4 billion, through an advice letter.
The RTBA is a two-way balancing account that tracks and records the GRC portion of actual financial risk transfer costs incurred compared to adopted amounts. Adopted amounts and actual costs incurred allocated to the Utility’s GT&S rate case and TO rate case will be recorded to authorized mechanisms applicable to those rate cases, specifically, the adjustment mechanism for GT&S-related amounts and the Utility’s FERC formula rates for TO related amounts.
For more information about the RTBA, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections
In response to the COVID-19 pandemic, on April 16, 2020, the CPUC adopted a resolution ordering utilities to implement a number of emergency customer protections for one year beginning on March 4, 2020 through April 16, 2021, including:
•waive deposit requirements for residential customers seeking to reestablish service for one year;
•implement payment plan options for residential customers;
•suspend disconnection for nonpayment and associated fees, waive deposit and late fee requirements for residential and small business customers;
•support low-income residential customers by:
◦freezing all standard and high-usage reviews for the CARE program eligibility for 12 months and potentially longer, as warranted;
◦contacting all community outreach contractors, the community-based organizations that assist in enrolling hard-to-reach low-income customers into CARE, to help better inform customers of these eligibility changes;
◦partnering with the program administrator of the customer funded emergency assistance program for low-income customers and increasing the assistance limit amount for the next 12 months; and
◦indicate how the energy savings assistance program can be deployed to assist customers;
•suspend all CARE and Federal Emergency Relief Administration program removals to avoid unintentional loss of the discounted rate during the period for which the customer is protected under these customer protections;
•discontinue generating all recertification and verification requests that require customers to provide their current income information;
•offer repair processing and timing assistance and timely access to utility customers;
•include these customer protections as part of their larger community outreach and public awareness plans;
•meet and confer with the CCAs as early as possible to discuss their roles and responsibilities for each emergency customer protection.
The resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the resolution. On February 11, 2021, the CPUC approved a resolution extending the moratorium on service disconnections for residential and small business customers to June 30, 2021.
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On June 11, 2020, the CPUC issued a final decision as part of the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs that permanently eliminated deposit requirements for residential customers. On December 21, 2020, a CPUC ALJ issued a ruling seeking comments on an approach to implement a temporary moratorium on service disconnections for medium-large commercial and industrial customers.
PG&E Corporation and the Utility are unable to predict whether this resolution will be extended or expanded to additional customer classes, which could have a material impact on results of operations, financial condition, and cash flows of PG&E Corporation and the Utility.
COVID-19 Pandemic Protections Memorandum Account
On May 1, 2020, the Utility submitted an advice letter to establish the CPPMA. The purpose of the CPPMA is to track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 Pandemic. Costs included in the CPPMA will include incremental uncollectibles expense for residential and small business customers, incremental financing costs as a result of lower accounts receivable collections for residential and small business customers, and the costs of complying with various customer protections described in “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections,” above. The Utility intends to seek recovery of the CPPMA balance in a future application, recovery of which will require CPUC reasonableness review.
On June 2, 2020 and July 15, 2020, the Utility submitted updated advice letters to modify and clarify prior proposals based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter.
The amount reflected in this memorandum account as of December 31, 2020 was $84 million, of which $76 million relates to incremental uncollectible expenses. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Other Regulatory Proceedings
Application to Sell General Office Complex
On September 30, 2020, the Utility filed an application with the CPUC to sell its SFGO located at 215 Market Street, 245 Market Street, 77 Beale Street, 50 Main Street, 25 Beale Street, and 45 Beale Street in downtown San Francisco, and to cover costs to relocate its staff at SFGO to a new headquarters to the Lakeside Building, and for appropriate ratemaking treatment of those transactions.
The Utility proposes the SFGO sale and headquarters transition proceed in several interrelated steps: the Utility has entered into a lease for the Lakeside Building with an option to purchase the Lakeside Building; the Utility will market and sell the SFGO, subject to CPUC approval; and the Utility will enter into an agreement with the buyer of the SFGO to lease back space during the multi-year relocation period (collectively, the “Transactions”). As space in the Lakeside Building becomes available following the expiration of existing tenants’ leases and completion of the redevelopment of the property to the Utility’s specifications, the Utility will relocate employees and operations from the SFGO and certain East Bay office locations to the Lakeside Building in phases over several years, beginning in 2022.
In this application, the Utility requests that the CPUC: (i) authorize the Utility to sell the SFGO pursuant to Public Utilities Code section 851, (ii) approve the Utility’s ratemaking proposal to distribute all of the gain on sale of the SFGO to customers over five years, beginning in 2022, (iii) approve the recovery of costs to lease back the SFGO after the buildings are sold, costs to lease the Lakeside Building, and other transition costs, and (iv) authorize the Utility to forecast the intended purchase of the Lakeside Building and include it in the Utility’s 2023 GRC. The Utility also proposes to establish a balancing account to record lease payments, net savings or costs on operating expense and capital expense, gain on sale, moving costs and related costs for inclusion in electric and gas rates.
On December 1, 2020, the CPUC held a prehearing conference in this matter. On December 15, 2020, the assigned commissioner issued a scoping memo, which sets forth the category, issues to be addressed, and schedule of the proceeding. The scoping memo contemplates a CPUC final decision as early as August 2021 and provides for additional timeline flexibility depending on the pace of the sale process.
PG&E Corporation and the Utility are unable to predict the timing and outcome of this proceeding.
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Application for Post-Emergence Securitization Transaction
On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. Among other uses, as a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust. Specifically, the application requests administration of the stress test methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are stress test costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also proposes a customer credit designed to equal the bond charges over the life of the bond, which would insulate customers from the charge on customer bills associated with the bonds. The Utility proposes to fund the customer credit through a trust that consists of shareholder assets including: (1) an initial contribution of $1.8 billion; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; and (3) investment returns on the assets in the trust. The Utility also proposes to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.
Protests and response to the application were due June 4, 2020 and the Utility filed a reply on June 12, 2020. A prehearing conference was held on June 18, 2020. The assigned commissioner issued the scoping memo on July 28, 2020 and directed the Utility to file updated testimony, if any, based on its post-emergence financial status by August 7, 2020. On August 7, 2020, the Utility served its updated testimony, in which it discussed, among other things, PG&E Corporation’s and Utility’s exit financings from Chapter 11 and related equity issuances, including to the Fire Victim Trust, in connection with consummating the Plan on July 1, 2020; issuance of revised credit ratings; updated financial forecasts for the Utility and their impacts on the securitization application, including on the stress test costs and the customer credit trust; and certain expected tax impacts.
Intervenor testimony was served on October 14, 2020, and the Utility’s rebuttal testimony was submitted on November 11, 2020. An evidentiary hearing was held on December 7-16, 2020. Opening briefs were submitted on January 15, 2021, and reply briefs were submitted on February 1, 2021. In a post-hearing briefing, the Utility and other parties in the proceeding included potential conditions and alternatives for the CPUC’s consideration. In post-hearing briefing, the Utility included an alternative proposal for the CPUC’s consideration comprised of four elements: (1) a $200 million increase in the initial shareholder contribution, from $1.8 billion to $2 billion, provided that $1 billion is contributed in 2021 and $1 billion in 2024; (2) potential shift in the customer credit trust’s investment portfolio to a greater proportion of fixed income investments; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) a reduced sharing of any trust surplus with customers to 10%. The Utility anticipates a CPUC decision in the second quarter of 2021.
On January 6, 2021, the Utility filed an application requesting that the CPUC issue a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to securitize the $7.5 billion of claims associated with the 2017 Northern California Wildfires referenced above. On January 7, 2021, the Utility filed a motion to consolidate the pending application seeking authorization for a post-emergence transaction and the application for a financing order. The ALJ granted the Utility’s motion to shorten the time for protests to January 22, 2021, and the Utility filed a reply on February 1, 2021. A prehearing conference was held on February 5, 2021. On February 10, 2021, certain intervenors filed a joint motion to dismiss the Utility’s application for a financing order. On February 17, 2021, the Utility filed a response opposing the motion to dismiss. Also on February 17, 2021, the PAO filed a response supporting the motion to dismiss. The Utility expects a CPUC decision on the financing order by May 6, 2021.
Application for AB 1054 Securitization Transaction
On February 24, 2021 the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to a principal amount of approximately $1.19 billion related to fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021. The $1.19 billion reflects capital expenditures related to the Utility’s Community Wildfire Safety Program, which were approved by the CPUC in the 2020 GRC, and include $655 million in recorded 2020 capital expenditures and an additional $535 million in forecast capital expenditures in 2021. The final amount to be securitized would be based on recorded 2020 and 2021 Community Wildfire Safety Program expenditures incurred by the Utility.
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The application requests that the CPUC issue a financing order authorizing one or more series of recovery bonds, determine that the issuance of the bonds and collection through fixed recovery charges is just and reasonable, consistent with the public interest and would reduce rates on a present value basis compared to traditional utility financing mechanisms, and authorize the Utility to collect a non-bypassable recovery charge sufficient to pay debt service on the recovery bonds. The application also requests to exclude the securitized debt from the Utility’s ratemaking capital structure and to adjust its GRC revenue requirement following the issuance of the recovery bonds. The proposed procedural schedule requests a final decision on all issues by June 24, 2021 and the application indicates that the issuance of the bonds is anticipated to occur before the end of 2021, but is subject to change.
2019 Wildfire Mitigation Plan
As previously disclosed, on October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility WMPs. This OIR provided guidance on the form and content of the initial WMPs, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of WMPs to be filed in future years. In this proceeding the CPUC determined, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as what additional elements beyond those required in SB 901 should be included in the WMPs. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation’s electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to WMPs, which SB 901 requires to be addressed in separate rate recovery applications.
On February 6, 2019, the Utility filed its first WMP, the 2019 WMP, with the CPUC, and amended it subsequently on February 12, 2019 and February 14, 2019. On May 30, 2019, the CPUC approved the 2019 WMP. (The Utility also filed an amendment to the plan on April 25, 2019, but CPUC approval did not extend to that amendment.)
2020-2022 Wildfire Mitigation Plan
As previously disclosed, on February 7, 2020, the Utility submitted its 2020 WMP and utility survey. The Utility’s 2020 WMP describes the Utility’s wildfire safety programs, which are focused on three key areas: reducing the potential for fires to be started by electrical equipment, reducing the potential for fires to spread, and minimizing the frequency, scope and duration of Public Safety Power Shut-off events, as well as providing historical data requested by the guidelines. The Utility’s 2020 WMP covers a three-year period from 2020-2022 but is updated annually.
On March 18, 2020, the CPUC issued a decision in this proceeding, clarifying that the CPUC’s newly created WSD would review 2020 WMPs, present resolutions for CPUC consideration on the 2020 Plans, and oversee independent evaluation and other compliance activity with regard to both 2019 and 2020 Plans.
On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved the Utility’s 2020 WMP. The resolutions indicate that while the Utility’s 2020 WMP met the minimum requirements for its submission, the deficiencies found, classified as severity level A, B, or C Conditions, require significant follow-up from the Utility and oversight to ensure appropriate remedies for the deficiencies. The Utility received 41 Conditions in total with the first set, classified as Class A Conditions, submitted on July 27, 2020. The second set, Class B Conditions, were completed on September 9, 2020 and the third, Class C Conditions, were submitted as part of the 2021 WMP update on February 5, 2021. On December 30, 2020, the WSD issued a Notice of Non-Compliance finding that the Utility’s responses to the Class A Conditions were insufficient. The WSD has required the Utility to include 39 action items in its 2021 WMP to address the insufficient responses. On January 8, 2021, the WSD issued a Notice of Non-Compliance finding that the Utility’s quarterly report addressing the Class B Conditions was insufficient. The WSD has directed the Utility to respond to 84 action items in its 2021 WMP or via a supplemental filing by February 26, 2021. Failure to remedy insufficiencies in the 2020-2022 WMP could lead to enforcement actions by the CPUC, including potentially placing the Utility in the Enhanced Oversight and Enforcement Process, and making the Utility unable to obtain an AB 1054 safety certification and, as a result, unable to access the Wildfire Fund, which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The Utility’s 2021 WMP was submitted on February 5, 2021. The 2021 WMP was an update to the 2020 WMP and addressed the Utility’s wildfire safety programs focused on reducing the potential for catastrophic wildfires related to electrical equipment, reducing the potential for fires to spread, and making PSPS events smaller, shorter and smarter for customers.
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PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 WMP, 2020 WMP, and 2021 WMP recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.
OIR Regarding Microgrids
As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC sought to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by spring or summer 2020, if not sooner. At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal contained three components for which it sought scope and cost recovery authorization of up to approximately $379 million in both expense and capital. On April 1, 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it was seeking to approximately $257 million. The Utility described in its supplemental testimony that it was focusing in 2020 on the use of temporary, mobile generation solutions to power microgrids in 2020, and that the Utility had suspended its solicitation for permanent generation located at substations with online dates in 2020. The Utility subsequently closed its solicitation for this permanent generation. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying the Utility’s motion to supplement its proposal.
The CPUC adopted a decision in the first track of the proceeding on June 11, 2020 (the “Track 1 Decision”), which approved with conditions the Utility’s proposal and requires the Utility to track costs in a new memorandum account for subsequent regulatory review and recovery in rates.
The CPUC initiated the second track of the proceeding on July 3, 2020, which focused on further implementation of SB 1339, as well as activity to shape the transition from diesel mobile generation to alternative, cleaner backup power generation. On January 14, 2021, the CPUC adopted a final decision in the second track of the proceeding (the “Track 2 Decision”). The Track 2 Decision requires the Utility to submit an Advice Letter to justify the amount of temporary generation necessary for use at substations during the 2021 wildfire season; to identify at least one clean substation project to pilot the use of diesel generation alternatives to power substation-level microgrids; to file an application by June 30, 2021 to propose a longer-term framework for substation generation solutions to mitigate PSPS outage events; and to file an application by September 30, 2021 to recover the costs incurred in 2020 associated with the use of temporary generation to mitigate PSPS outages. The Track 2 Decision also authorizes the Utility to record the future costs of temporary generation for substations in a memorandum account, with recovery of those costs through the general rate case or a separate application. The costs for the clean substation project(s) are authorized to be recovered through a one-way balancing account established by the Track 2 Decision, up to a $350 million cap and subject to other eligibility requirements.
In addition, the Track 2 Decision requires that the Utility: (1) modify its existing electric rules to allow certain critical facilities to be powered during grid outages by adjacent premises; (2) establish a new tariff to facilitate the commercialization and development of single-customer, single-account microgrids; (3) develop a new microgrid incentive program that compliments the Utility’s existing Community Microgrid Enablement Program and expands the incentives available for certain eligible community microgrids up to a statewide combined budget of $200 million; and (4) create a new process and associated criteria to evaluate technologies to isolate customer electrical loads for the purpose of forming microgrids during grid outages. The Track 2 Decision establishes an agenda for ongoing meetings of the CPUC’s Resiliency and Microgrids Working Group.
On February 9, 2020, the CPUC issued an amended scoping memo initiating Track 3 of the proceeding. In Track 3, the CPUC intends to address whether utilities, including the Utility, should waive standby charges for a customer operating a microgrid under certain circumstances. Further, the CPUC states that in a future Track 4 of the proceeding, it intends to address: (1) multi-property microgrid tariffs and alternatives; (2) methodologies to value resiliency; (3) microgrid interconnection issues; and (4) revisit its initial determinations with regard to a single-property microgrid tariff.
Failure to obtain a substantial or full recovery of costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization
As previously disclosed, on October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications “that will result from the confirmation of a plan of reorganization and other regulatory approvals necessary to resolve” the Chapter 11 Cases (the “Chapter 11 Proceedings OII”).
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On May 28, 2020, the CPUC approved a final decision in this proceeding. As previously disclosed, the decision approved the Plan with certain conditions and modifications related to certain topics, including but not limited to, governance, operational structure, safety performance, executive competition, and financial condition. On September 17, 2020, the CPUC issued a proposed decision that would close the proceeding. On October 22, 2020, the CPUC approved the decision.
Enhanced Oversight and Enforcement Process
In the Chapter 11 Proceedings OII final decision, the CPUC adopted an Enhanced Oversight and Enforcement Process designed to provide a roadmap for how the CPUC will monitor the Utility’s performance on an ongoing basis. The Enhanced Oversight and Enforcement Process contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. These trigger events include failure to obtain an approved WMP, failure to comply with regulatory reporting requirements, insufficient progress toward approved safety or risk-driven investments and failure to comply with or demonstrate sufficient progress toward certain metrics (some of which will be determined in an ongoing regulatory proceeding). The Enhanced Oversight and Enforcement Process also contains provisions for the Utility to cure and permanently exit the Enhanced Oversight and Enforcement Process if it can satisfy specific criteria. If the Utility is placed into the Enhanced Oversight and Enforcement Process, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The Enhanced Oversight and Enforcement Process does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and Orders Instituting Investigations and to impose fines and penalties. The Enhanced Oversight and Enforcement Process requires the Utility to report the occurrence of a triggering event to the CPUC’s Executive Director no later than five business days after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.
On November 24, 2020, the Utility received a letter from the President of the CPUC, expressing concerns related to the Utility’s vegetation and asset management activities and explaining potential implications with respect to the CPUC’s Enhanced Oversight and Enforcement Process, as well as the Utility’s annual safety certification under California AB 1054. According to the Letter, the President of the CPUC has “directed CPUC staff to conduct fact-finding to determine whether a recommendation to place [the Utility] into the enhanced oversight and enforcement process is warranted.”
The Utility is unable to predict whether additional fines, penalties, or other regulatory actions may be taken.
Regionalization Proposal
On June 30, 2020, the Utility filed its application for approval of its Regionalization Proposal with the CPUC. The Utility’s proposal would divide its service area into five new regions to further improve safety and reliability, core operations, and be more responsive to the needs of its customers. The Utility’s Regionalization Proposal describes the development of these regions, plans to hire new regional leadership, and a new regional organization structure. The Utility’s application requests the CPUC to approve a memorandum account to record any incremental costs the Utility incurs in connection with the development and implementation of regionalization. The Utility will file an updated Regionalization Proposal with the CPUC on February 26, 2021.
The Utility is unable to predict the timing and outcome of this application.
Wildfire Fund Non-Bypassable Charge
In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of an NBC to support the Wildfire Fund. On October 24, 2019, the CPUC issued a final decision finding that the imposition of the NBC is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the IOUs as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision proposes revenue requirements for the Utility of $404.6 million, which is based on average annual collections and shall expire at the end of the year 2035.
On November 25, 2019, an individual intervenor filed an application for rehearing of the decision arguing that the decision constitutes a constitutional violation of procedural due process and an unjust and unreasonable rate increase. On March 2, 2020, the CPUC issued a decision denying the application for rehearing.
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On July 16, 2020, the CPUC approved the Wildfire Fund NBC servicing orders between the California Department of Water Resources and the Large Electrical Corporations to impose the Wildfire Fund NBC. On September 10, 2020, the CPUC ordered the Utility to cease collection of the DWR Bond Charge related revenue requirement from electric customers in their respective territories. The final month in which a Bond Charge related revenue requirement was imposed to collect revenue from electric customers of the Utilities was September 2020.
On September 24, 2020, the CPUC ordered the Utility to collect the Wildfire Fund NBC from eligible customers from October 1, 2020 through December 31, 2020 in the amount of $0.00580 per kilowatt-hour.
On September 29, 2020, the Utility submitted an advice letter to submit tariffs incorporating final rates that was effective October 1, 2020. In addition to submitting tariff revisions that include final rates as outlined, the letter included the tariff revisions needed to cease the imposition of the DWR Bond Charge and implement the Wildfire Fund Charge.
On December 17, 2020, the CPUC approved the Utility to collect the Wildfire Fund NBC from eligible customers from January 1, 2021 through December 31, 2021 in the amount of $0.00580 per kilowatt-hour. On December 30, 2020, the Utility submitted an advice letter to submit tariffs incorporating final rates effective January 1, 2021. The advice letter is still pending CPUC approval.
On February 22, 2021, the CPUC issued a proposed decision regarding the amount of the Wildfire Non-Bypassable Charge in 2022 and 2023. The prehearing conference and scoping memo are expected to take place in April, 2021.
Transportation Electrification
As previously disclosed, on May 31, 2018, pursuant to a state law authorizing the Utility to conduct programs to support and incent the deployment of electric vehicles, the CPUC issued a final decision approving the Utility’s two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets.
On February 3, 2020, in a rulemaking to consider further utility-sponsored programs to support electric vehicles and transportation electrification, the CPUC issued a draft Transportation Electrification Framework for review and comment. The CPUC held workshops on the draft framework in 2020, and approval of the framework and guidance for future electric vehicle programs is expected in 2021.
Also in 2020, the California Legislature passed, and the Governor signed, a new law that authorizes the Utility and other California IOUs to invest in new electric distribution infrastructure to support electric vehicles without requiring electric vehicle customers to pay certain of the infrastructure costs that other customers are required to pay for non-electric vehicle infrastructure costs. Instead, the incremental electric vehicle infrastructure costs will be paid by the Utility’s electric customers as common utility costs in the Utility’s periodic general rate cases.
OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas Planning
On January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the GHG reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding will examine whether recent industry related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including but not limited to, gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders.
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The Utility filed opening comments on the preliminary scope on February 26, 2020 and reply comments on March 12, 2020. The assigned ALJ and assigned commissioner held a prehearing conference on March 24, 2020. The Utility filed a post-prehearing conference statement on April 1, 2020. On April 23, 2020, the assigned commissioner issued a ruling setting the final scope, schedule and categorization for phase 1 (Tracks 1A and 1B). On July 7, the CPUC held a workshop to address natural gas reliability standards (Track 1A) and on July 21, 2020 a second workshop was held to address market structure and regulations (Track 1B). On October 2, 2020, the assigned ALJ issued a ruling, including the workshop report and staff recommendations. The Utility filed opening comments on the report on November 2, 2020 and filed reply comments on November 17, 2020. As directed in the October 2, 2020 ruling, the Utility held a workshop on November 30, 2020 to address intraday demand and grid reliability. On December 24, 2020, the ALJ issued a ruling that modified the schedule. The Utility filed its proposal to address gas supply and cost allocation issues described in the workshop report on January 8, 2021. Parties filed comments on January 29, 2021 and reply comments on February 12, 2021.
OIR to Consider Strategies and Guidance for Climate Change Adaptation
On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings.
On October 24, 2019, the CPUC adopted a final decision on a portion of phase one (Topic 1 and 2), defining climate change adaptation for California’s energy utilities as “adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations.” In addition, this decision provides guidance on what data should be used by the IOUs to perform all climate impact, climate risk, and climate vulnerability analyses undertaken with respect to their infrastructure assets, operations, and customer impacts. Finally, this decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers.
On October 22, 2019, the CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed each of the large IOUs to research and develop a new form of risk assessment, a CVA. CVAs instruct utilities to “examine the risks posed by climate change to their core lines of business, including generation, transmission, distribution, and storage, irrespective of who owns the assets.” In addition, the staff proposal provides guidance regarding the data sources to be used in the CVA, outreach and coordination with the community, and incorporation of CVA findings into RAMP and GRC filings. The Utility provided opening and reply comments on February 18, 2020 and March 3, 2020, respectively.
On August 27, 2020, the CPUC adopted a final decision on Topics 4 and 5, regarding adaptation outreach to disadvantaged communities and detailed requirements for each IOU’s CVA. The CPUC instructed each IOU to establish a “climate change team,” with cross-departmental responsibilities, which will report directly to a designated executive at the SVP level or above. Each IOU must disclose to the CPUC such changes in organizational structure, listing the individual names and department titles of all internal participants. Board members should oversee and prioritize climate adaptation planning, as informed by senior leadership. Each IOU is required to consider climate risks to assets, operations, and services over which IOUs have direct control. Additionally, the decision directs the IOUs to seek to obtain an acknowledgement in new contracts with third party providers that the operator has considered long-term climate risk. Each IOUs’ completed CVA will coincide with its RAMP filing during its four-year GRC cycle, and each IOU must detail resulting climate adaptation measures in a new chapter in its future GRC applications. Each IOU must file a Community Engagement Plan detailing community outreach on climate adaptation, covering every disadvantaged vulnerable community and leveraging existing IOU community outreach on other matters. The IOUs’ climate adaptation Community Engagement Plan proposals must be filed one year prior to their CVA, with the Utility’s first Community Engagement Plan due in June 2023, as the Utility’s first CVA under this decision will be due in June 2024. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account, was authorized to cover CVA costs and incremental costs of outreach.
OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions
On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California.
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On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8.
On January 30, 2020, the CPUC proposed new guidelines in phase two of this proceeding. On May 28, 2020, the CPUC adopted PSPS Phase 2 Guidelines, which require utilities to restore energy within 24 hours after the end of a PSPS event where possible; to consult with critical facilities on back-up power for PSPS events; and to support access and functional needs populations during PSPS events, including powering medical equipment at customer resource centers.
On August 24, 2020, the ALJ issued a decision addressing two joint motions that had been filed in the proceeding. The first motion filed on April 13, 2020 requested emergency protocols during the COVID-19 pandemic. The second motion filed on June 15, 2020 requested that the CPUC perform a reasonableness review of past IOU PSPS events to determine whether each was reasonable. The August 24, 2020 decision found that, with respect to the first joint motion, the May 28, 2020 decision dealt with many of the issues raised; and with respect to the second joint motion, the CPUC already performed reasonableness reviews of IOU PSPS events.
On December 2, 2020, the Utility and other parties submitted comments in this proceeding in response to an August 3, 2020 scoping ruling regarding SED’s report in a separate PSPS-related proceeding, OII to Examine the Late 2019 Public Safety Power Shutoff Events. In their comments, the Utility and other parties commented that issues raised in SED’s report should be addressed in a rulemaking setting. The Utility is unable to predict the timing and outcome of this proceeding.
On November 12, 2019, the assigned commissioner and ALJ issued an order to show cause directing the Utility to show why it should not be sanctioned for violations of law or CPUC decisions related to the PSPS events of October 9-12, 2019, October 23-25, 2019, and October 26-November 1, 2019.
The Utility submitted its testimony with the CPUC on February 5, 2020. Other parties submitted their testimony on February 28, 2020, and the Utility submitted its concurrent rebuttal testimony on April 7, 2020. On September 21, 2020, the assigned commissioner and the ALJ issued an order that required the Utility to respond to certain factual questions and concluded that with the provision of responsive answers to those questions, evidentiary hearings would not be needed in the proceeding. Opening briefs were filed on October 30, 2020, by all parties, which included an intervenor proposing financial penalties against the Utility of $166 million. If adopted by the CPUC, such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Reply briefs were filed by all parties on November 17, 2020, including the Utility, which opposed the imposition of any penalties.
On February 19, 2021, the CPUC proposed new guidelines in Phase 3 of this proceeding. If adopted, these guidelines would require utilities to submit annual pre- and post- season reports, have certain percentages of Community Resource Centers be indoors, have a webpage that explains “critical facility” requirements, and conduct de-energization simulation exercises. Parties will comment in March 2021, and a proposed decision is expected in May 2021, with a final decision in June 2021.
The Utility is unable to predict the outcome of this proceeding.
OII to Examine the Late 2019 Public Safety Power Shutoff Events
On November 13, 2019, the CPUC issued an OII to determine “whether California’s IOUs prioritized safety and complied with the CPUC’s regulations and requirements with respect to their PSPS events in late 2019.” The first phase of this proceeding focuses on (1) the effectiveness of the utility’s procedures to notify the public of the PSPS events, (2) the utility’s communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utility’s management of its resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary.
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On June 8, 2020, the SED issued a public report on the Late 2019 Public Safety Power Shutoff Events. The report identified certain shortcomings in each of the electric IOUs’ implementation of the CPUC’s PSPS Guidelines during their late 2019 PSPS events but stated that its findings were intended to be advisory in nature, subject to modification, and not intended to serve as an adjudicatory staff investigatory pre-enforcement report. On August 3, 2020, the assigned commissioner issued a ruling and scoping memo directing parties to file comments on SED’s report and the following two issues: (1) whether the Utility and other IOUs in October and November 2019 complied with the criteria set forth in applicable laws and regulations when pro-actively deenergizing and re-energizing their power lines, and (2) what corrective actions the CPUC should require of the Utility and other IOUs for any failure in late 2019 to comply with the then-existing PSPS guidelines. Each of the IOUs filed their comments on September 2, 2020, intervenors filed their comments on October 16, 2020, and reply comments were filed by all parties on November 16, 2020. Several parties proposed in their comments that penalties be imposed on the utilities for inadequate implementation of the PSPS events. For example, TURN proposed that the CPUC should treat each customer affected by a PSPS event, for which the IOU has not adequately demonstrated that the benefits outweigh the public safety risks, as a separate offense, with each offense subject to a penalty of no less than $500 and no more than $100,000. In reply comments, the Utility argued that the proposed penalties should not be adopted for procedural and substantive reasons. If adopted by the CPUC, such penalties could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
The proposed decision is expected in the first quarter of 2021, and the CPUC’s final decision is anticipated no sooner than 30 days after the proposed decision. The Utility is unable to predict the outcome of this proceeding.
Power Charge Indifference Adjustment OIR
In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the PCIA, a cost recovery mechanism to ensure that customers that leave the Utility’s bundled service for a non-Utility provider, such as a DA or CCA provider, pay their fair share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf. The above market costs of the Utility’s generation portfolio are calculated using benchmarks for energy, RA and RPS attributes.
As previously disclosed, on October 11, 2018, the CPUC approved a phase one decision to modify the PCIA methodology. The Utility implemented a revised PCIA reflecting this decision in rates as of July 1, 2019.
Also, as previously disclosed, on October 10, 2019, the CPUC approved a final decision that finalized the true-up for the new PCIA methodology.
On March 26, 2020, the CPUC approved a final decision on departing load forecasting and PCIA bill presentation issues, establishing that the IOUs shall show a PCIA line item in their tariffs and bill summary tables on all customer bills, which shall be implemented by the last business day of 2021.
On June 30, 2020, the CPUC issued a PD that would provide a non-Utility provider an option to prepay their entire PCIA obligation. On August 6, 2020 the CPUC issued a final decision adopting a framework for prepayment agreements for PCIA obligations.
The proceeding is now examining structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the Utility’s portfolios. On December 16, 2020, the assigned commissioner issued an amended scoping memo and ruling expanding the rulemaking’s scope to include the potential modification of the annual PCIA rate cap and potential changes to the Utility’s cost recovery and rate setting proceedings to improve PCIA and ERRA alignment.
The Utility is unable to predict the outcome of this proceeding.
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Central Procurement of the Resource Adequacy Program
On June 17, 2020, the CPUC issued a decision on the Central Procurement of the RA program. The decision shifts local RA procurement responsibility under the CPUC’s RA program from all load serving entities to a CPE in two distribution service areas, including the Utility’s distribution service area, resulting in a change from decentralized to centralized local RA procurement in those distribution service areas. The decision also adopted implementation details for the central procurement of multi-year local RA, ordered the Utility and another IOU to serve as the CPE for their respective distribution service areas, and adopted a hybrid central procurement framework for the multi-year local RA program beginning for the 2023 RA compliance year.
The decision requires the Utility, as the CPE for its distribution service area, to conduct a competitive, all-source solicitation for local RA procurement, with any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, or any load serving entity or third-party with an existing local RA contract eligible to bid into the solicitation.
Subsequently, on December 3, 2020, the CPUC issued a follow-up decision adopting a compensation mechanism applicable to certain local resources that may be procured by the CPE for purposes of reducing the total CPE procurement requirements. This mechanism applies to new preferred local resources and new local energy storage resources, including utility-owned generation. Procurement by the Utility of, and compensation for, such resources shall occur outside of the competitive, all-source solicitation.
The Cost Allocation Mechanism methodology is adopted as the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function. The administrative costs incurred in serving the central procurement entity function shall also be recoverable under the Cost Allocation Mechanism.
Integrated Resource Planning Procurement
On November 13, 2019, the CPUC issued a decision that takes a number of steps to address the potential for system RA shortages beginning in 2021. The decision requires incremental procurement of system-level qualifying RA capacity of 3,300 MWs by all LSEs operating within the CAISO’s balancing area for the period 2021-2023, of which the Utility is responsible for 716.9 MWs for its bundled customer portion. The decision requires that at least 50% of LSE resource responsibilities come online by August 1, 2021, at least 75% by August 1, 2022, and the remaining by August 1, 2023. Additionally, the decision directs the IOUs to act as the backstop procurement agent for CCAs and Energy Service Providers (ESPs) that choose not to voluntarily self-procure or that fail to meet their procurement responsibilities after electing to self-provide their assigned MWs of system RA capacity under the decision. On April 15, 2020, the ALJ issued a ruling that the Utility must procure 48.2 MWs of RA capacity for LSEs that chose to opt-out of voluntarily self-providing their required portion.
The Utility has procured its required RA capacity for the August 1, 2021 milestone from third parties through CPUC-approved contracts for lithium ion battery energy storage resources with terms ranging from 10-15 years. On December 22, 2020, the Utility filed an advice letter seeking CPUC approval of an additional group of similar contracts that would satisfy the balance of the Utility’s procurement obligations for the August 1, 2022 and August 1, 2023 milestones.
The CPUC is developing a Modified Cost Allocation Mechanism methodology, under which the Utility will be able to recover procurement and administrative costs it incurs in serving the backstop procurement function.
OIR to Further Develop a Risk-Based Decision-Making Framework for Electric and Gas Utilities
On July 20, 2020, the CPUC initiated a rulemaking proceeding to consider ways to strengthen the risk-based decision-making framework that regulated energy utilities use to assess, manage, mitigate and minimize safety risks. The rulemaking will build on requirements for a utility risk framework adopted in the first Safety Model Assessment Proceeding. The CPUC’s goal is to further the prioritization of safety by electric and gas utilities.
On November 2, 2020, the assigned commissioner issued a scoping memo establishing the scope, schedule, and categorization for Phase I and Phase II of the proceeding. Phase I, which began November 2020, will consider (i) clarifications to the technical requirements of the risk-based decision-making framework; (ii) safety and operational performance metrics; and (iii) refining RAMP procedural requirements.
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On November 17, 2020, the assigned commissioner issued a ruling regarding the development of safety and operational metrics for the Utility. The ruling directed the Utility to propose metrics that are “suitable for the use as triggering events as specified in the Enhanced Oversight and Enforcement Process” and “suitable, over time, for the Commission, intervenors, and the public to potentially use to gauge the safety and operational performance of all gas and electric IOUs.” On January 15, 2021, the Utility filed a response proposing 12 safety and operational metrics using the criteria outlined by the ruling. On January 25, 2021, parties filed responses to the Utility’s proposal. On January 28, 2021, the CPUC hosted a public workshop where the Utility, the other IOUs, and intervenors commented on the Utility’s safety and operational metrics proposal. All parties may file comments on the Utility’s safety and operational metrics by March 1, 2021.
OIR to Revisit Net Energy Metering Tariffs
On August 17, 2020, the CPUC initiated a rulemaking proceeding to develop a successor to the existing NEM tariffs. The successor tariff is being developed pursuant to the requirements of AB 327. Under AB 327, the successor to the existing NEM tariffs should provide customer-generators with credit or compensation for electricity generated by their renewable facilities based on the value of that generation to all customers and allows customer-sited renewable generation to grow sustainably among different types of customers.
On November 19, 2020, the assigned commissioner and the ALJ issued a scoping memo and ruling for this proceeding. The scoping memo separated the proceeding into two phases. In the first phase, the CPUC will address several issues including, but not limited to, determining the principles to assist in the development and evaluation of a successor to the current NEM tariffs, assessing what information from a study on existing tariffs should inform the successor, outlining the methods to use to analyze the program elements and the resulting proposals, and determining the program elements or specific features that should be included in the successor tariff. In the second phase, the CPUC will consider what additional or enhanced consumer protections for customers should be adopted, as well as other issues that may arise, such as the virtual net energy metering tariffs, NEM aggregation tariff, the Renewable Energy Self-Generation Bill Credit Transfer program, and the NEM fuel cell tariff.
On January 5, 2021, the ALJ issued a PD that outlined eight guiding principles to assist in the development and evaluation of proposals for successor to the current NEM tariff. The Utility filed comments on January 25, 2021, and reply comments on February 1, 2021. On February 11, 2021, the CPUC issued a final decision on the guiding principles.
OIR to Address Energy Utility Customer Debt Accumulated during the Coronavirus Pandemic
On February 11, 2021, the CPUC initiated a rulemaking proceeding to consider arrearage relief for utility customers who will have outstanding utility bills when the moratorium on service disconnections ends. The OIR will evaluate a more global program beyond the currently approved arrearage management program focused on low-income residential customers that is funded by the Utility’s customers. The OIR may consider various funding approaches for this expanded debt forgiveness proposal, which could include shareholder funding.
The CPUC has indicated that it expects to issue a proposed decision on May 21, 2021 and a final decision on June 24, 2021.
The Utility is unable to predict the outcome of this proceeding.
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LEGISLATIVE AND REGULATORY INITIATIVES
Senate Bill 350
On June 30, 2020, the California governor signed into law SB 350 (the Golden State Energy Act), a bill which authorizes the creation by the 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 only in the event that the CPUC determines that the Utility’s Certificate of Public Convenience and Necessity should be revoked pursuant to any process or procedures adopted by the CPUC in its decision approving PG&E Corporation’s and the Utility’s Plan of Reorganization.
Senate Bill 901
SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the CHT. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.
Assembly Bill 1054
On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund 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, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054.
AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.) AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. On February 24, 2021, the Utility filed an application with the CPUC seeking authorization for a transaction to securitize up to a principal amount of approximately $1.19 billion related to fire risk mitigation capital expenditures that have been or will be incurred by the Utility in 2020 and 2021.
Each of California’s large IOUs have elected to participate in the Wildfire Fund. On July 1, 2020, having satisfied the conditions for the Utility’s participation in the Wildfire Fund, the Utility deposited approximately $5 billion in the Wildfire Fund, which represents PG&E’s initial and first annual contributions. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.
ENVIRONMENTAL MATTERS
The Utility’s operations are subject to extensive federal, state, and local laws and permits 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 the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Item 1A. Risk Factors, “Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)
RISK MANAGEMENT ACTIVITIES
PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit. The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes.
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Commodity Price Risk
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.
The Utility’s current authorized revenue requirement for natural gas transportation and storage service to non-core customers is not balancing account protected. The Utility recovers these costs in its gas transmission and storage rate cases through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $14 million and $9 million at December 31, 2020 and 2019, respectively. (See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. for further discussion of price risk management activities.)
Interest Rate Risk
Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2020 and 2019, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the impact on net income over the next 12 months would be $89 million and $45 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding. (See Note 5 of the Notes to the Consolidated Financial Statements in Item 8. for further discussion of interest rates.)
Energy Procurement Credit Risk
The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas and related services, then the Utility may find it necessary to procure electricity or gas at current market prices or seek alternate services, which may be higher than the contract prices.
The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility executes many energy contracts under master commodity enabling agreements that may require security. Security may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Security or performance assurance may be required from the Utility or counterparties when current net receivables/payables and exposure exceed contractually specified limits.
The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:
| (in millions) | Exposure (1) | Number of Wholesale Customers or Counterparties >10% | Net Credit Exposure to Wholesale Customers or Counterparties >10% | ||||||||||||||
| December 31, 2020 | $ | 250 | 2 | $ | 57 | ||||||||||||
December 31, 2019 (2) | $ | 381 | 3 | $ | 36 | ||||||||||||
(1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties. For purposes of this table, parental guarantees are not included as part of the calculation. Exposure amounts reported above do not include adjustments for time value or liquidity.
(2) Exposure balance has been updated to show the maximum positive exposure, including excess collateral postings, instead of the net credit exposure disclosed in prior periods.
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CRITICAL ACCOUNTING POLICIES
The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates and assumptions. These accounting policies and their key characteristics are outlined below.
Contributions to the Wildfire Fund
On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of December 31, 2020, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.
As of December 31, 2020, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire fund asset, and $5.8 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2020, the Utility recorded amortization and accretion expense of $413 million. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire fund expense in the Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.
AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation results in the estimated number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Starting with a 5-year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.
Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.
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PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ service territories in 2020 for which the cause is currently unknown and which may in the future be determined to be covered by the Wildfire Fund. At December 31, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.
Loss Contingencies
As discussed below, PG&E Corporation and the Utility have recorded material accruals for various wildfire-related, enforcement and legal matters, and environmental remediation liabilities. PG&E Corporation and the Utility have also recorded insurance receivables for third-party claims.
Wildfire-Related Liabilities
PG&E Corporation and the Utility are subject to potential liabilities related to wildfires. PG&E Corporation and the Utility record a wildfire-related liability when it determines that a loss is probable and it can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.
Potential liabilities related to wildfires depend on various factors, including but not limited to negotiations and settlements or the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation or the Utility. For example, the Utility’s wildfire-related accruals have changed in the past as new facts and information became available to the Utility, including the availability of new evidence and additional information about the scope and nature of damages. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
Enforcement and Litigation Matters
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. Actual results may differ materially from these estimates and assumptions. (See Note 14 and “Enforcement and Litigation Matters” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.)
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Environmental Remediation Liabilities
The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former manufactured gas plant sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.
The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has a program related to certain former manufactured gas plant sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.
At December 31, 2020 and 2019, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion. The Utility’s undiscounted future costs could increase to as much as $2.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.
Insurance Receivable
The Utility has liability insurance from various insurers, which provides coverage for third-party claims. The Utility records insurance recoveries only when a third-party claim is recorded and it is deemed probable that a recovery of that claim will occur and the Utility can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future events. Insurance recoveries are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, discussions with insurers and other information and events pertaining to a particular matter. (See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
Regulatory Accounting
As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or refund to, customers. Despite the ongoing losses related to wildfires (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.), there is no actual or anticipated change in the cost of service regulation of the Utility’s operations. Therefore, the Utility continues to apply the accounting ASC 980, Regulated Operations. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and Regulated Operations” in Note 3 as well as Note 4 of the Notes to the Consolidated Financial Statements in Item 8. At December 31, 2020, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $11.4 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $12.0 billion.
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Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. The CPUC has not denied the recovery of any material costs previously recognized by the Utility as regulatory assets for the periods presented. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or revenue recognition.
A portion of the Utility's regulatory asset balances relate to items which could not be anticipated by the Utility during CPUC GRC rate requests resulting from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs. In addition, the CPPMA account tracks costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 Pandemic. While the Utility believes such costs are recoverable, rate recovery requires CPUC authorization in separate proceedings or through a GRC. (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,” “Regulatory Matters - Wildfire Mitigation Memorandum and Balancing Accounts,” and “Regulatory Matters - COVID-19 Pandemic Protections Memorandum Account.”)
Additionally, SB 901 provides a mechanism for the CPUC to potentially allow recovery in future rates, through a securitization mechanism, of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. The Utility must evaluate the likelihood of recovery in future rates each period. If the criteria are met at a later date, the Utility would recognize a regulatory asset and a related gain in the consolidated income statement in the period in which it is determined that the likelihood of recovery is probable.
In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors.
Asset Retirement Obligations
PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. (See Notes 3 and 4 of the Notes to the Consolidated Financial Statements in Item 8.)
To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.
At December 31, 2020, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $6.4 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.
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Pension and Other Postretirement Benefit Plans
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery from customers. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)
The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. (See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.)
In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2020 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond.
Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the Utility’s defined benefit pension plan, the assumed return of 5.1% compares to a ten-year actual return of 9.6%.
The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 835 Aa-grade non-callable bonds at December 31, 2020. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:
| (in millions) | Increase (Decrease) in Assumption | Increase in 2020 Pension Costs | Increase in Projected Benefit Obligation at December 31, 2020 | ||||||||||||||
| Discount rate | (0.50) | % | $ | 77 | $ | 1,979 | |||||||||||
| Rate of return on plan assets | (0.50) | % | 92 | — | |||||||||||||
| Rate of increase in compensation | 0.50 | % | 43 | 435 | |||||||||||||
The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:
| (in millions) | Increase (Decrease) in Assumption | Increase in 2020 Other Postretirement Benefit Costs | Increase in Accumulated Benefit Obligation at December 31, 2020 | ||||||||||||||
| Health care cost trend rate | 0.50 | % | $ | 9 | $ | 66 | |||||||||||
| Discount rate | (0.50) | % | 11 | 150 | |||||||||||||
| Rate of return on plan assets | (0.50) | % | 13 | — | |||||||||||||
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NEW ACCOUNTING PRONOUNCEMENTS
See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Operating Revenues | |||||||||||||||||
| Electric | $ | 13,858 | $ | 12,740 | $ | 12,713 | |||||||||||
| Natural gas | 4,611 | 4,389 | 4,046 | ||||||||||||||
Total operating revenues | 18,469 | 17,129 | 16,759 | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Cost of electricity | 3,116 | 3,095 | 3,828 | ||||||||||||||
| Cost of natural gas | 782 | 734 | 671 | ||||||||||||||
| Operating and maintenance | 8,684 | 8,725 | 7,153 | ||||||||||||||
| Wildfire-related claims, net of insurance recoveries | 251 | 11,435 | 11,771 | ||||||||||||||
| Wildfire fund expense | 413 | — | — | ||||||||||||||
| Depreciation, amortization, and decommissioning | 3,468 | 3,234 | 3,036 | ||||||||||||||
Total operating expenses | 16,714 | 27,223 | 26,459 | ||||||||||||||
| Operating Income (Loss) | 1,755 | (10,094) | (9,700) | ||||||||||||||
| Interest income | 39 | 82 | 76 | ||||||||||||||
| Interest expense | (1,260) | (934) | (929) | ||||||||||||||
| Other income, net | 483 | 250 | 424 | ||||||||||||||
| Reorganization items, net | (1,959) | (346) | — | ||||||||||||||
| Loss Before Income Taxes | (942) | (11,042) | (10,129) | ||||||||||||||
| Income tax provision (benefit) | 362 | (3,400) | (3,292) | ||||||||||||||
| Net Loss | (1,304) | (7,642) | (6,837) | ||||||||||||||
| Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 | ||||||||||||||
| Loss Attributable to Common Shareholders | $ | (1,318) | $ | (7,656) | $ | (6,851) | |||||||||||
| Weighted Average Common Shares Outstanding, Basic | 1,257 | 528 | 517 | ||||||||||||||
| Weighted Average Common Shares Outstanding, Diluted | 1,257 | 528 | 517 | ||||||||||||||
| Net Loss Per Common Share, Basic | $ | (1.05) | $ | (14.50) | $ | (13.25) | |||||||||||
| Net Loss Per Common Share, Diluted | $ | (1.05) | $ | (14.50) | $ | (13.25) | |||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PG&E CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Net Loss | $ | (1,304) | $ | (7,642) | $ | (6,837) | |||||||||||
| Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $7, $0, and $2, at respective dates) | (17) | (1) | 4 | ||||||||||||||
| Total other comprehensive income (loss) | (17) | (1) | 4 | ||||||||||||||
| Comprehensive Loss | (1,321) | (7,643) | (6,833) | ||||||||||||||
| Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 | ||||||||||||||
| Comprehensive Loss Attributable to Common Shareholders | $ | (1,335) | $ | (7,657) | $ | (6,847) | |||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PG&E CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions)
| Balance at December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| ASSETS | |||||||||||
| Current Assets | |||||||||||
| Cash and cash equivalents | $ | 484 | $ | 1,570 | |||||||
| Restricted Cash | 143 | 7 | |||||||||
| Accounts receivable | |||||||||||
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) | 1,883 | 1,287 | |||||||||
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) | 1,083 | 969 | |||||||||
| Regulatory balancing accounts | 2,001 | 2,114 | |||||||||
| Other | 1,172 | 2,617 | |||||||||
| Regulatory assets | 410 | 315 | |||||||||
| Inventories | |||||||||||
| Gas stored underground and fuel oil | 95 | 97 | |||||||||
| Materials and supplies | 533 | 550 | |||||||||
| Wildfire fund asset | 464 | — | |||||||||
| Other | 1,334 | 639 | |||||||||
| Total current assets | 9,602 | 10,165 | |||||||||
| Property, Plant, and Equipment | |||||||||||
| Electric | 66,982 | 62,707 | |||||||||
| Gas | 24,135 | 22,688 | |||||||||
| Construction work in progress | 2,757 | 2,675 | |||||||||
| Other | 20 | 20 | |||||||||
| Total property, plant, and equipment | 93,894 | 88,090 | |||||||||
| Accumulated depreciation | (27,758) | (26,455) | |||||||||
| Net property, plant, and equipment | 66,136 | 61,635 | |||||||||
| Other Noncurrent Assets | |||||||||||
| Regulatory assets | 8,978 | 6,066 | |||||||||
| Nuclear decommissioning trusts | 3,538 | 3,173 | |||||||||
| Operating lease right of use asset | 1,741 | 2,286 | |||||||||
| Wildfire fund asset | 5,816 | — | |||||||||
| Income taxes receivable | 67 | 67 | |||||||||
| Other | 1,978 | 1,804 | |||||||||
| Total other noncurrent assets | 22,118 | 13,396 | |||||||||
| TOTAL ASSETS | $ | 97,856 | $ | 85,196 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
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PG&E CORPORATION
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
| Balance at December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current Liabilities | |||||||||||
| Short-term borrowings | $ | 3,547 | $ | — | |||||||
| Long-term debt, classified as current | 28 | — | |||||||||
| Debtor-in-possession financing, classified as current | — | 1,500 | |||||||||
| Accounts payable | |||||||||||
| Trade creditors | 2,402 | 1,954 | |||||||||
| Regulatory balancing accounts | 1,245 | 1,797 | |||||||||
| Other | 580 | 566 | |||||||||
| Operating lease liabilities | 533 | 556 | |||||||||
| Disputed claims and customer refunds | 242 | — | |||||||||
| Interest payable | 498 | 4 | |||||||||
| Wildfire-related claims | 2,250 | — | |||||||||
| Other | 2,256 | 1,254 | |||||||||
| Total current liabilities | 13,581 | 7,631 | |||||||||
| Noncurrent Liabilities | |||||||||||
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) | 37,288 | — | |||||||||
| Regulatory liabilities | 10,424 | 9,270 | |||||||||
| Pension and other postretirement benefits | 2,444 | 1,884 | |||||||||
| Asset retirement obligations | 6,412 | 5,854 | |||||||||
| Deferred income taxes | 1,398 | 320 | |||||||||
| Operating lease liabilities | 1,208 | 1,730 | |||||||||
| Other | 3,848 | 2,573 | |||||||||
| Total noncurrent liabilities | 63,022 | 21,631 | |||||||||
| Liabilities Subject to Compromise | — | 50,546 | |||||||||
| Contingencies and Commitments (Notes 14 and 15) | |||||||||||
| Equity | |||||||||||
| Shareholders' Equity | |||||||||||
Common stock, no par value, authorized 3,600,000,000 and 800,000,000 shares at respective dates; 1,984,678,673 and 529,236,741 shares outstanding at respective dates | 30,224 | 13,038 | |||||||||
| Reinvested earnings | (9,196) | (7,892) | |||||||||
| Accumulated other comprehensive loss | (27) | (10) | |||||||||
| Total shareholders' equity | 21,001 | 5,136 | |||||||||
| Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 | |||||||||
| Total equity | 21,253 | 5,388 | |||||||||
| TOTAL LIABILITIES AND EQUITY | $ | 97,856 | $ | 85,196 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
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PG&E CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash Flows from Operating Activities | |||||||||||||||||
| Net loss | $ | (1,304) | $ | (7,642) | $ | (6,837) | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation, amortization, and decommissioning | 3,468 | 3,234 | 3,036 | ||||||||||||||
| Allowance for equity funds used during construction | (140) | (79) | (129) | ||||||||||||||
| Deferred income taxes and tax credits, net | 1,097 | (2,948) | (2,532) | ||||||||||||||
| Reorganization items, net (Note 2) | 1,458 | 108 | — | ||||||||||||||
| Wildfire fund expense | 413 | — | — | ||||||||||||||
| Disallowed capital expenditures | 17 | 581 | (45) | ||||||||||||||
| Other | 399 | 207 | 332 | ||||||||||||||
| Effect of changes in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | (1,182) | (104) | (121) | ||||||||||||||
| Wildfire-related insurance receivable | 1,564 | 35 | (1,698) | ||||||||||||||
| Inventories | 6 | (80) | (73) | ||||||||||||||
| Accounts payable | 58 | 516 | 409 | ||||||||||||||
Wildfire-related claims | (16,525) | (114) | 13,665 | ||||||||||||||
| Income taxes receivable/payable | — | 23 | (23) | ||||||||||||||
| Other current assets and liabilities | (1,079) | 77 | (281) | ||||||||||||||
| Regulatory assets, liabilities, and balancing accounts, net | (2,451) | (1,417) | (800) | ||||||||||||||
| Liabilities subject to compromise | 413 | 12,222 | — | ||||||||||||||
| Contributions to wildfire fund | (5,200) | — | — | ||||||||||||||
| Other noncurrent assets and liabilities | (142) | 197 | (151) | ||||||||||||||
| Net cash provided by (used in) operating activities | (19,130) | 4,816 | 4,752 | ||||||||||||||
| Cash Flows from Investing Activities | |||||||||||||||||
| Capital expenditures | (7,690) | (6,313) | (6,514) | ||||||||||||||
| Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,518 | 956 | 1,412 | ||||||||||||||
| Purchases of nuclear decommissioning trust investments | (1,590) | (1,032) | (1,485) | ||||||||||||||
| Other | 14 | 11 | 23 | ||||||||||||||
Net cash used in investing activities | (7,748) | (6,378) | (6,564) | ||||||||||||||
| Cash Flows from Financing Activities | |||||||||||||||||
| Proceeds from debtor-in-possession credit facility | 500 | 1,850 | — | ||||||||||||||
| Repayments of debtor-in-possession credit facility | (2,000) | (350) | — | ||||||||||||||
| Debtor-in-possession credit facility debt issuance costs | (6) | (113) | — | ||||||||||||||
| Bridge facility financing fees | (73) | — | — | ||||||||||||||
| Repayment of long-term debt | (764) | — | (795) | ||||||||||||||
| Borrowings under credit facilities | 8,554 | — | 3,960 | ||||||||||||||
| Repayments under credit facilities | (3,949) | — | (775) | ||||||||||||||
| Credit facilities financing fees | (22) | — | — | ||||||||||||||
Net repayments of commercial paper, net of discount of $0, $0, and $1 at respective dates | — | — | (182) | ||||||||||||||
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates | 1,448 | — | 600 | ||||||||||||||
| Short-term debt matured | — | — | (750) | ||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $178, $0, and $7 at respective dates | 13,497 | — | 793 | ||||||||||||||
| Exchanged debt financing fees | (103) | — | — | ||||||||||||||
| Common stock issued | 7,582 | 85 | 200 | ||||||||||||||
| Equity Units issued | 1,304 | — | — | ||||||||||||||
| Other | (40) | (8) | (20) | ||||||||||||||
| Net cash provided by financing activities | 25,928 | 1,464 | 3,031 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | (950) | (98) | 1,219 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at January 1 | 1,577 | 1,675 | 456 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at December 31 | $ | 627 | $ | 1,577 | $ | 1,675 | |||||||||||
| Less: Restricted cash and restricted cash equivalents | (143) | (7) | (7) | ||||||||||||||
| Cash and cash equivalents at December 31 | $ | 484 | $ | 1,570 | $ | 1,668 | |||||||||||
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| Supplemental disclosures of cash flow information | |||||||||||||||||
| Cash paid for: | |||||||||||||||||
| Interest, net of amounts capitalized | $ | (1,563) | $ | (10) | $ | (786) | |||||||||||
| Income taxes, net | — | — | (49) | ||||||||||||||
Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
| Capital expenditures financed through accounts payable | $ | 515 | $ | 826 | $ | 368 | |||||||||||
| Operating lease liabilities arising from obtaining ROU assets | 13 | 2,816 | — | ||||||||||||||
| Common stock issued in satisfaction of liabilities | 8,276 | — | — | ||||||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PG&E CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except share amounts)
| Common Stock Shares | Common Stock Amount | Reinvested Earnings | Accumulated Other Comprehensive Loss | Total Shareholders' Equity | Non- controlling Interest - Preferred Stock of Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | 514,755,845 | $ | 12,632 | $ | 6,596 | $ | (8) | $ | 19,220 | $ | 252 | $ | 19,472 | ||||||||||||||||||||||||||||
| Net loss | — | — | (6,837) | — | (6,837) | — | (6,837) | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | 5 | (1) | 4 | — | 4 | ||||||||||||||||||||||||||||||||||
| Common stock issued, net | 5,582,865 | 200 | — | — | 200 | — | 200 | ||||||||||||||||||||||||||||||||||
| Stock-based compensation amortization | — | 78 | — | — | 78 | — | 78 | ||||||||||||||||||||||||||||||||||
| Preferred stock dividend requirement of subsidiary | — | — | (14) | — | (14) | — | (14) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 520,338,710 | $ | 12,910 | $ | (250) | $ | (9) | $ | 12,651 | $ | 252 | $ | 12,903 | ||||||||||||||||||||||||||||
| Net loss | — | — | (7,642) | — | (7,642) | — | (7,642) | ||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (1) | (1) | — | (1) | ||||||||||||||||||||||||||||||||||
| Common stock issued, net | 8,898,031 | 85 | — | — | 85 | — | 85 | ||||||||||||||||||||||||||||||||||
| Stock-based compensation amortization | — | 43 | — | — | 43 | — | 43 | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 529,236,741 | $ | 13,038 | $ | (7,892) | $ | (10) | $ | 5,136 | $ | 252 | $ | 5,388 | ||||||||||||||||||||||||||||
| Net loss | — | — | (1,304) | — | (1,304) | — | (1,304) | ||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (17) | (17) | — | (17) | ||||||||||||||||||||||||||||||||||
| Common stock issued, net | 1,455,441,932 | 15,854 | — | — | 15,854 | — | 15,854 | ||||||||||||||||||||||||||||||||||
| Equity units issued | — | 1,304 | — | — | 1,304 | — | 1,304 | ||||||||||||||||||||||||||||||||||
| Stock-based compensation amortization | — | 28 | — | — | 28 | — | 28 | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 1,984,678,673 | $ | 30,224 | $ | (9,196) | $ | (27) | $ | 21,001 | $ | 252 | $ | 21,253 | ||||||||||||||||||||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Operating Revenues | |||||||||||||||||
| Electric | $ | 13,858 | $ | 12,740 | $ | 12,713 | |||||||||||
| Natural gas | 4,611 | 4,389 | 4,047 | ||||||||||||||
| Total operating revenues | 18,469 | 17,129 | 16,760 | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Cost of electricity | 3,116 | 3,095 | 3,828 | ||||||||||||||
| Cost of natural gas | 782 | 734 | 671 | ||||||||||||||
| Operating and maintenance | 8,707 | 8,750 | 7,153 | ||||||||||||||
| Wildfire-related claims, net of insurance recoveries | 251 | 11,435 | 11,771 | ||||||||||||||
| Wildfire fund expense | 413 | — | — | ||||||||||||||
| Depreciation, amortization, and decommissioning | 3,469 | 3,233 | 3,036 | ||||||||||||||
Total operating expenses | 16,738 | 27,247 | 26,459 | ||||||||||||||
| Operating Income (Loss) | 1,731 | (10,118) | (9,699) | ||||||||||||||
| Interest income | 39 | 82 | 74 | ||||||||||||||
| Interest expense | (1,111) | (912) | (914) | ||||||||||||||
| Other income, net | 470 | 239 | 426 | ||||||||||||||
| Reorganization items, net | (310) | (320) | — | ||||||||||||||
| Income (Loss) Before Income Taxes | 819 | (11,029) | (10,113) | ||||||||||||||
| Income tax provision (benefit) | 408 | (3,407) | (3,295) | ||||||||||||||
| Net Income (Loss) | 411 | (7,622) | (6,818) | ||||||||||||||
| Preferred stock dividend requirement | 14 | 14 | 14 | ||||||||||||||
| Income (Loss) Available for Common Stock | $ | 397 | $ | (7,636) | $ | (6,832) | |||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Net Income (Loss) | $ | 411 | $ | (7,622) | $ | (6,818) | |||||||||||
| Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates) | (6) | 2 | (5) | ||||||||||||||
| Total other comprehensive income (loss) | (6) | 2 | (5) | ||||||||||||||
| Comprehensive Income (Loss) | $ | 405 | $ | (7,620) | $ | (6,823) | |||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(in millions)
Balance at December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| ASSETS | |||||||||||
| Current Assets | |||||||||||
| Cash and cash equivalents | $ | 261 | $ | 1,122 | |||||||
| Restricted Cash | 143 | 7 | |||||||||
| Accounts receivable | |||||||||||
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) | 1,883 | 1,287 | |||||||||
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) | 1,083 | 969 | |||||||||
| Regulatory balancing accounts | 2,001 | 2,114 | |||||||||
| Other | 1,180 | 2,647 | |||||||||
| Regulatory assets | 410 | 315 | |||||||||
| Inventories | |||||||||||
| Gas stored underground and fuel oil | 95 | 97 | |||||||||
| Materials and supplies | 533 | 550 | |||||||||
| Wildfire fund asset | 464 | — | |||||||||
| Other | 1,321 | 628 | |||||||||
| Total current assets | 9,374 | 9,736 | |||||||||
| Property, Plant, and Equipment | |||||||||||
| Electric | 66,982 | 62,707 | |||||||||
| Gas | 24,135 | 22,688 | |||||||||
| Construction work in progress | 2,757 | 2,675 | |||||||||
| Other | 18 | 18 | |||||||||
| Total property, plant, and equipment | 93,892 | 88,088 | |||||||||
| Accumulated depreciation | (27,756) | (26,453) | |||||||||
| Net property, plant, and equipment | 66,136 | 61,635 | |||||||||
| Other Noncurrent Assets | |||||||||||
| Regulatory assets | 8,978 | 6,066 | |||||||||
| Nuclear decommissioning trusts | 3,538 | 3,173 | |||||||||
| Operating lease right of use asset | 1,736 | 2,279 | |||||||||
| Wildfire fund asset | 5,816 | — | |||||||||
| Income taxes receivable | 66 | 66 | |||||||||
| Other | 1,818 | 1,659 | |||||||||
| Total other noncurrent assets | 21,952 | 13,243 | |||||||||
| TOTAL ASSETS | $ | 97,462 | $ | 84,614 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
| Balance at December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||
| Current Liabilities | |||||||||||
| Short-term borrowings | $ | 3,547 | $ | — | |||||||
| Debtor-in-possession financing, classified as current | — | 1,500 | |||||||||
| Accounts payable | |||||||||||
| Trade creditors | 2,366 | 1,949 | |||||||||
| Regulatory balancing accounts | 1,245 | 1,797 | |||||||||
| Other | 624 | 675 | |||||||||
| Operating lease liabilities | 530 | 553 | |||||||||
| Disputed claims and customer refunds | 242 | — | |||||||||
| Interest payable | 444 | 4 | |||||||||
| Wildfire-related claims | 2,250 | — | |||||||||
| Other | 2,248 | 1,263 | |||||||||
Total current liabilities | 13,496 | 7,741 | |||||||||
| Noncurrent Liabilities | |||||||||||
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) | 32,664 | — | |||||||||
| Regulatory liabilities | 10,424 | 9,270 | |||||||||
| Pension and other postretirement benefits | 2,328 | 1,884 | |||||||||
| Asset retirement obligations | 6,412 | 5,854 | |||||||||
| Deferred income taxes | 1,570 | 442 | |||||||||
| Operating lease liabilities | 1,206 | 1,726 | |||||||||
| Other | 3,886 | 2,626 | |||||||||
| Total noncurrent liabilities | 58,490 | 21,802 | |||||||||
| Liabilities Subject to Compromise | — | 49,736 | |||||||||
| Contingencies and Commitments (Notes 14 and 15) | |||||||||||
| Shareholders' Equity | |||||||||||
| Preferred stock | 258 | 258 | |||||||||
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates | 1,322 | 1,322 | |||||||||
| Additional paid-in capital | 28,286 | 8,550 | |||||||||
| Reinvested earnings | (4,385) | (4,796) | |||||||||
| Accumulated other comprehensive income | (5) | 1 | |||||||||
| Total shareholders' equity | 25,476 | 5,335 | |||||||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 97,462 | $ | 84,614 | |||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash Flows from Operating Activities | |||||||||||||||||
| Net income (loss) | $ | 411 | $ | (7,622) | $ | (6,818) | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation, amortization, and decommissioning | 3,469 | 3,233 | 3,036 | ||||||||||||||
| Allowance for equity funds used during construction | (140) | (79) | (129) | ||||||||||||||
| Deferred income taxes and tax credits, net | 1,141 | (2,952) | (2,548) | ||||||||||||||
| Reorganization items, net (Note 2) | (90) | 97 | — | ||||||||||||||
| Wildfire fund expense | 413 | — | — | ||||||||||||||
| Disallowed capital expenditures | 17 | 581 | (45) | ||||||||||||||
| Other | 370 | 167 | 258 | ||||||||||||||
| Effect of changes in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | (1,160) | (132) | (122) | ||||||||||||||
| Wildfire-related insurance receivable | 1,564 | 35 | (1,698) | ||||||||||||||
| Inventories | 6 | (80) | (73) | ||||||||||||||
| Accounts payable | (24) | 579 | 421 | ||||||||||||||
| Wildfire-related claims | (16,525) | (114) | 13,665 | ||||||||||||||
| Income taxes receivable/payable | — | 5 | (5) | ||||||||||||||
| Other current assets and liabilities | (1,141) | 101 | (301) | ||||||||||||||
| Regulatory assets, liabilities, and balancing accounts, net | (2,451) | (1,417) | (800) | ||||||||||||||
| Liabilities subject to compromise | 401 | 12,194 | — | ||||||||||||||
| Contributions to wildfire fund | (5,200) | — | — | ||||||||||||||
| Other noncurrent assets and liabilities | (108) | 214 | (137) | ||||||||||||||
| Net cash provided by (used in) operating activities | (19,047) | 4,810 | 4,704 | ||||||||||||||
| Cash Flows from Investing Activities | |||||||||||||||||
| Capital expenditures | (7,690) | (6,313) | (6,514) | ||||||||||||||
| Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,518 | 956 | 1,412 | ||||||||||||||
| Purchases of nuclear decommissioning trust investments | (1,590) | (1,032) | (1,485) | ||||||||||||||
| Other | 14 | 11 | 23 | ||||||||||||||
Net cash used in investing activities | (7,748) | (6,378) | (6,564) | ||||||||||||||
| Cash Flows from Financing Activities | |||||||||||||||||
| Proceeds from debtor-in-possession credit facility | 500 | 1,850 | — | ||||||||||||||
| Repayments of debtor-in-possession credit facility | (2,000) | (350) | — | ||||||||||||||
| Debtor-in-possession credit facility debt issuance costs | (6) | (97) | — | ||||||||||||||
| Bridge facility financing fees | (33) | — | — | ||||||||||||||
| Repayment of long-term debt | (100) | (445) | |||||||||||||||
| Borrowings under credit facilities | 8,554 | — | 3,535 | ||||||||||||||
| Repayments under credit facilities | (3,949) | — | (650) | ||||||||||||||
| Credit facilities financing fees | (22) | — | — | ||||||||||||||
Net repayments of commercial paper, net of discount of $0 at respective dates | — | — | (50) | ||||||||||||||
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates | 1,448 | — | 250 | ||||||||||||||
| Short-term debt matured | — | — | (750) | ||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $88, $0, and $7 at respective dates | 8,837 | — | 793 | ||||||||||||||
| Exchanged debt financing fees | (103) | — | — | ||||||||||||||
| Equity contribution from PG&E Corporation | 12,986 | — | 45 | ||||||||||||||
| Other | (42) | (8) | (20) | ||||||||||||||
| Net cash provided by financing activities | 26,070 | 1,395 | 2,708 | ||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | (725) | (173) | 848 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at January 1 | 1,129 | 1,302 | 454 | ||||||||||||||
| Cash, cash equivalents, and restricted cash at December 31 | $ | 404 | $ | 1,129 | $ | 1,302 | |||||||||||
| Less: Restricted cash and restricted cash equivalents | (143) | (7) | (7) | ||||||||||||||
| Cash and cash equivalents at December 31 | $ | 261 | $ | 1,122 | $ | 1,295 | |||||||||||
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| Supplemental disclosures of cash flow information | |||||||||||||||||
| Cash paid for: | |||||||||||||||||
| Interest, net of amounts capitalized | $ | (1,458) | $ | (7) | $ | (773) | |||||||||||
| Income taxes, net | — | — | (59) | ||||||||||||||
Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
| Capital expenditures financed through accounts payable | $ | 515 | $ | 826 | $ | 368 | |||||||||||
| Operating lease liabilities arising from obtaining ROU assets | 13 | 2,807 | — | ||||||||||||||
| Common stock equity infusion from PG&E Corporation used to satisfy liabilities | 6,750 | — | — | ||||||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in millions)
| Preferred Stock | Common Stock | Additional Paid-in Capital | Reinvested Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity | ||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | $ | 258 | $ | 1,322 | $ | 8,505 | $ | 9,656 | $ | 6 | $ | 19,747 | |||||||||||||||||||||||
| Net loss | — | — | — | (6,818) | — | (6,818) | |||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | 2 | (7) | (5) | |||||||||||||||||||||||||||||
| Equity contribution | — | — | 45 | — | — | 45 | |||||||||||||||||||||||||||||
| Preferred stock dividend | — | — | — | (14) | — | (14) | |||||||||||||||||||||||||||||
| Balance at December 31, 2018 | $ | 258 | $ | 1,322 | $ | 8,550 | $ | 2,826 | $ | (1) | $ | 12,955 | |||||||||||||||||||||||
| Net loss | — | — | — | (7,622) | — | (7,622) | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||
| Balance at December 31, 2019 | $ | 258 | $ | 1,322 | $ | 8,550 | $ | (4,796) | $ | 1 | $ | 5,335 | |||||||||||||||||||||||
| Net income | — | — | — | 411 | — | 411 | |||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | (6) | (6) | |||||||||||||||||||||||||||||
| Equity contribution | — | — | 19,736 | — | — | 19,736 | |||||||||||||||||||||||||||||
| Balance at December 31, 2020 | $ | 258 | $ | 1,322 | $ | 28,286 | $ | (4,385) | $ | (5) | $ | 25,476 | |||||||||||||||||||||||
See accompanying Notes to the Consolidated Financial Statements.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
Organization and Basis of Presentation
PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.
This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).
The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.
Chapter 11 Filing and Going Concern
The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection on January 29, 2019. Uncertainty regarding these matters previously raised substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns.
As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on the Effective Date of July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date the financial statements were issued. (For more information regarding the Chapter 11 Cases, see Note 2 below.)
NOTE 2: BANKRUPTCY FILING
Chapter 11 Proceedings
On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.
123
Significant Bankruptcy Court Actions
Plan of Reorganization and Restructuring Support Agreements
On June 19, 2020, PG&E Corporation and the Utility and the Shareholder Proponents filed the Plan. On June 20, 2020, the Bankruptcy Court confirmed the Plan by issuing the Confirmation Order. PG&E Corporation and the Utility emerged from Chapter 11 on the Effective Date of July 1, 2020.
On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA with certain holders of wildfire insurance subrogation claims (such claims, the “Subrogation Claims”). On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. As of December 31, 2020, PG&E Corporation and the Utility incurred $53 million in professional fees related to the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 14 for further information on the Subrogation RSA.
On December 6, 2019, PG&E Corporation and the Utility entered the TCC RSA, which was subsequently amended on December 16, 2019, with the TCC, the attorneys and other advisors and agents for holders of claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and Public Entity Wildfire Claims (as defined below)) (the “Fire Victim Claims”) that are signatories to the TCC RSA, and the Shareholder Proponents. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 14 for further information on the TCC RSA.
On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” therein and the Shareholder Proponents. On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA.
Confirmation of the Plan of Reorganization
The Plan as confirmed by the Confirmation Order provides for certain transactions and the satisfaction and treatment of claims against and interests in PG&E Corporation and the Utility, each in accordance with the terms of the Plan, including the transactions described below. The Plan provides for the following treatment of various classes of claims as described below. PG&E Corporation and the Utility are in the process of resolving and paying claims pursuant to the treatment provided under the Plan.
•PG&E Corporation and the Utility funded the Fire Victim Trust for the benefit of all holders of Fire Victim Claims, whose claims were channeled to the Fire Victim Trust on the Effective Date with no recourse to PG&E Corporation and the Utility. In full and final satisfaction, release, and discharge of all Fire Victim Claims, the Fire Victim Trust was funded with $5.4 billion in cash (with an additional $1.35 billion in cash to be funded on a deferred basis), common stock of PG&E Corporation representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments), plus the assignment of certain rights and causes of action. As a result of such funding, all Fire Victim Claims have been satisfied, released, discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility;
•PG&E Corporation and the Utility funded a trust (the “Subrogation Wildfire Trust”) for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. As a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility;
•PG&E Corporation and the Utility paid $1.0 billion in cash to certain local public entities (the “Settling Public Entities”) that entered into PSAs with PG&E Corporation and the Utility and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities in full and final satisfaction, release and discharge of such Settling Public Entities’ wildfire related claims;
124
•The following pre-petition notes of the Utility: (a) 3.50% Senior Notes due October 1, 2020; (b) 4.25% Senior Notes due May 15, 2021; (c) 3.25% Senior Notes due September 15, 2021; and (d) 2.45% Senior Notes due August 15, 2022), (collectively, the “Utility Short-Term Senior Notes”); the following pre-petition notes of the Utility: (a) 6.05% Senior Notes due March 1, 2034; (b) 5.80% Senior Notes due March 1, 2037; (c) 6.35% Senior Notes due February 15, 2038; (d) 6.25% Senior Notes due March 1, 2039; (e) 5.40% Senior Notes due January 15, 2040; and (f) 5.125% Senior Notes due November 15, 2043, (collectively, the “Utility Long-Term Senior Notes) and the pre-petition credit agreements of the Utility, including in connection with the pollution control bonds (except for $100 million of pollution control bonds (Series 2008F and 2010E), which were repaid in cash) (collectively, the “Utility Funded Debt”) were refinanced and all other Utility pre-petition senior notes (collectively, the “Utility Reinstated Senior Notes”) were reinstated and collateralized on or around the Effective Date through the issuance of a corresponding series of first mortgage bonds of the Utility;
•PG&E Corporation paid in full all of its pre-petition funded debt obligations that were allowed in the Chapter 11 Cases;
•PG&E Corporation and the Utility repaid all borrowings under the DIP Facilities and have paid all other allowed administrative expense claims in accordance with the Plan;
•Holders of allowed claims by a governmental authority entitled to priority in payment under sections 502(i) and 507(a)(8) of the Bankruptcy Code (“Priority Tax Claims”) have received or will receive in the future, cash in an amount equal to such allowed Priority Tax Claims;
•Holders of allowed secured claims other than Priority Tax Claims or secured claims related to the DIP Facilities (“Other Secured Claims”) have received or will receive cash in an amount equal to such Other Secured Claims;
•Holders of allowed claims other than administrative expense claims or Priority Tax Claims, entitled to priority in payment as specified in section 507(a)(3), (4), (5), (6), (7), or (9) of the Bankruptcy Code (“Priority Non-Tax Claims”) have received or will receive cash in an amount equal to such allowed Priority Non-Tax Claims;
•PG&E Corporation and the Utility will pay in full all pre-petition unsecured claims that do not fall within any of the other classes of unsecured claims under the Plan (“General Unsecured Claims”) that are allowed in the Chapter 11 Cases; and
•PG&E Corporation and the Utility will pay in full all allowed claims that are subject to subordination under section 510(b) of the Bankruptcy Code other than subordinated claims related to the common stock of PG&E Corporation (“Subordinated Debt Claims”). PG&E Corporation will provide to each holder of an allowed claim that relates to the common stock of PG&E Corporation that is subject to subordination under section 510(b) of the Bankruptcy Code (a “HoldCo Rescission or Damage Claim”) a number of shares of PG&E Corporation common stock based on a formula as specified in the Plan that varies depending on when the claimant purchased the affected shares of common stock and reduces the amount of the allowed claim by the amount of insurance proceeds, if any, received by the claimant on account of all or any portion of an allowed HoldCo Rescission or Damage Claim.
In addition, the Plan also provides for the following in connection with or following the implementation of the Plan:
•Holders of claims related to the 2016 Ghost Ship fire are entitled to pursue their claims against PG&E Corporation and the Utility (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);
•Holders of certain claims may be able to pursue their claims against PG&E Corporation and the Utility, such as administrative expense claims that have not been satisfied or come due by the Effective Date, claims arising from wildfires occurring after the Petition Date that have not been satisfied by the Effective Date (including the 2019 Kincade fire (as defined in Note 14 below)), and claims relating to certain FERC refund proceedings, workers’ compensation benefits and certain environmental claims;
•PG&E Corporation or the Utility, as applicable, assumed all of their respective power purchase agreements and community choice aggregation servicing agreements; and
•PG&E Corporation or the Utility, as applicable, assumed all of their respective pension obligations, other employee obligations, and collective bargaining agreements with labor.
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The Confirmation Order contains a channeling injunction that is also in the Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Claims will be from the Subrogation Wildfire Trust and the sole source of recovery for holders of Fire Victim Claims will be from the Fire Victim Trust. The holders of such claims will have no recourse to or claims whatsoever against PG&E Corporation and the Utility or their assets and properties on account of such claims.
The Plan as confirmed by the Confirmation Order provides for certain financing transactions as follows:
•one or more equity offerings of up to $9.0 billion of gross proceeds in cash through the issuance of common stock and/or other equity and/or equity-linked securities pursuant to one or more offerings and/or private placements;
•the issuance of $4.75 billion of new PG&E Corporation debt;
•the reinstatement of $9.575 billion of pre-petition debt of the Utility; and
•the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of the Utility’s 4.55% Senior Notes due 2030 and 4.95% Senior Notes due 2050 (the “New Utility Long-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (ii) $1.75 billion of the Utility’s 3.45% Senior Notes due 2025 and 3.75% Senior Notes due 2028 (the “New Utility Short-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (iii) $3.9 billion of the Utility’s 3.15% Senior Notes due 2026 and 4.50% Senior Notes due 2040 (the “New Utility Funded Debt Exchange Bonds”) to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date) (see Note 5 below for a description of the debt transactions that occurred on or before the Effective Date).
The foregoing financing transactions occurred on or around the Effective Date.
On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility paid the first tranche of tax benefits of approximately $758 million pursuant to the Tax Benefits Payment Agreement.
Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust (the “Fire Victim Trust Assignment Agreement”), pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477.0 million shares of PG&E Corporation common stock. As a result of the Additional Units Issuance (as described in Note 6 below) on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement.
Further, on the Effective Date, PG&E Corporation and the Utility funded a $10 million fund established for the benefit of the Supporting Public Entities (refer to “Plan Support Agreements with Public Entities” in Note 14 below) under the PSAs in accordance with the terms of the Plan and the PSAs with the Supporting Public Entities, and also made a payment of $1.0 billion in cash to the public entities who are party to the PSAs with the Supporting Public Entities. Also, on the Effective Date, PG&E Corporation and the Utility funded $100 million to the Subrogation Wildfire Trust and placed the balance of the $11.0 billion in a segregated escrow account established and owned by the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims, which was subsequently paid to the Subrogation Wildfire Trust.
Equity Financing
In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments. For more information, see Note 6 below.
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Equity Backstop Commitments and Forward Stock Purchase Agreements
As of March 6, 2020, PG&E Corporation entered into Chapter 11 Plan Backstop Commitment Letters (collectively, as amended by the Consent Agreements (as defined below), the “Backstop Commitment Letters”) with the Backstop Parties, pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). As a result of PG&E Corporation emerging from Chapter 11 on July 1, 2020, the Backstop Commitments were not utilized and terminated in accordance with their terms.
The commitment premium for the Backstop Commitments was paid in shares (the “Backstop Commitment Premium Shares”) of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119 million shares of PG&E Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12.0 billion). PG&E Corporation issued the Backstop Commitment Premium Shares to the Backstop Parties on the Effective Date in connection with emerging from Chapter 11.
On June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of expense related to the Backstop Commitment Premium Shares in Reorganization items, net (as defined below). This amount was primarily based on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing price was $9.03 per share and as a result, PG&E Corporation recorded an additional $19 million expense in the third quarter of 2020.
Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters. As of December 31, 2020, PG&E Corporation recorded $49 million in professional fees and related expenses to the Backstop Parties in Reorganization items, net.
In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the transactions contemplated by the Plan (the “Offerings”), up to $523 million was issuable pursuant to customary options granted to the underwriters thereof to purchase the Option Securities (as defined below in Note 6).
On June 19, 2020, PG&E Corporation entered into the Forward Stock Purchase Agreements with the Backstop Parties. Each Forward Stock Purchase Agreement provided that, subject to certain conditions, the Backstop Party would purchase on the Effective Date, and receive on such settlement date as designated in the Forward Stock Purchase Agreement (the “Settlement Date”) an amount of common stock of PG&E Corporation (such shares, each Backstop Party’s “Greenshoe Backstop Shares”) equal to its pro rata share of the value of the Option Securities not purchased by the underwriters (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount” and all Greenshoe Backstop Purchase Amounts in the aggregate, the “Aggregate Greenshoe Backstop Purchase Amount”), at a price per share equal to the lesser of (i) the lowest per share price of common stock sold on an underwritten basis to the public in an offering of common stock of PG&E Corporation, as disclosed on the cover page of the prospectus or prospectus supplement, and (ii) the price per share payable by the investors party to the Investment Agreement dated as of June 7, 2020 (such lesser price, the “Settlement Price”). The Settlement Price was $9.50 per share. Each Forward Stock Purchase Agreement expired on August 3, 2020.
On June 25, 2020, the Backstop Parties funded the Greenshoe Backstop Purchase Amount to PG&E Corporation in the amount of $523 million, which was recorded in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation applied the proceeds of such funding to distributions under the Plan on the Effective Date. On August 3, 2020, PG&E Corporation redeemed $120.5 million of the Forward Stock Purchase Agreements payable in cash as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement (as defined below in Note 6). On August 3, 2020, PG&E Corporation delivered 42.3 million Greenshoe Backstop Shares to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that was not redeemed.
Additionally, each Forward Stock Purchase Agreement provided that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation would issue to each Backstop Party its pro rata share of 50 million shares of common stock (such shares, each Backstop Party’s “Additional Backstop Premium Shares”). The Additional Backstop Premium Shares were issued to Backstop Parties on the Effective Date. On June 30, 2020, PG&E Corporation recorded $444 million of expense related to the Additional Backstop Premium Shares in Reorganization items, net. This amount was based primarily on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a result, PG&E Corporation recorded an additional $8 million expense in the third quarter of 2020.
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Financial Reporting in Reorganization
Effective on the Petition Date and up to June 30, 2020, PG&E Corporation and the Utility applied accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that were directly associated with reorganization proceedings must have been reported separately as reorganization items, net in the Consolidated Statements of Income. In addition, the balance sheet must have distinguished pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that were not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that were not debtors in the Chapter 11 Cases in the Consolidated Balance Sheets. LSTC are pre-petition obligations that were not fully secured and had at least a possibility of not being repaid at the full claim amount. Where there was uncertainty about whether a secured claim would be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility classified the entire amount of the claim as LSTC.
Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Pursuant to the Plan and Confirmation Order, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date were subject to an injunction and were subject to treatment under the Plan. These claims were reflected as LSTC in the Consolidated Balance Sheets at December 31, 2019. Additional claims may arise for contingencies and other unliquidated and disputed amounts.
PG&E Corporation’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.
The Utility’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.
Upon emergence from Chapter 11 on July 1, 2020, PG&E Corporation and the Utility were not required to apply fresh start accounting based on the provisions of ASC 852 since the entity’s reorganization value immediately before the date of confirmation was more than the total of all its post-petition liabilities and allowed claims.
Liabilities Subject to Compromise
As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities was subject to compromise or other treatment pursuant to the Plan. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are subject to an injunction and will be satisfied pursuant to the Plan and the Chapter 11 claims reconciliation process.
Prior to June 30, 2020, pre-petition liabilities that were subject to compromise were required to be reported at the amounts expected to be allowed. Therefore, liabilities subject to compromise as of December 31, 2019 in the table below reflected management’s estimates of amounts expected to be allowed in the Chapter 11 Cases, based upon, among other things, the status of negotiations with creditors. As of June 30, 2020, such amounts were reclassified to current or non-current liabilities in the Condensed Consolidated Balance Sheets, based upon management’s judgment as to the timing for settlement of such liabilities.
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Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified as of December 31, 2020 consist of the following:
| (in millions) | Utility | PG&E Corporation (1) | December 31, 2019 PG&E Corporation Consolidated | Change in Estimated Allowed Claim 2020 (2) | Cash Payment | Reclassified as of June 30, 2020 (3) | Utility | PG&E Corporation (1) | December 31, 2020 PG&E Corporation Consolidated | ||||||||||||||||||||||||||||||||||||||||||||
Financing debt | $ | 22,450 | $ | 666 | $ | 23,116 | $ | 351 | $ | — | $ | (23,467) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||
Wildfire-related claims | 25,548 | — | 25,548 | 18 | (23) | (25,543) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Trade creditors (4) | 1,183 | 5 | 1,188 | 6 | (14) | (1,180) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Non-qualified benefit plan | 20 | 137 | 157 | — | — | (157) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| 2001 bankruptcy disputed claims | 234 | — | 234 | 4 | — | (238) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Customer deposits & advances | 71 | — | 71 | 12 | — | (83) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Other | 230 | 2 | 232 | 59 | — | (291) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Total Liabilities Subject to Compromise | $ | 49,736 | $ | 810 | $ | 50,546 | $ | 450 | $ | (37) | $ | (50,959) | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||||||||||
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims,” “customer deposits & advances,” and “other” line items which are mainly due to the adjustment to recorded liabilities.
(3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets.
(4) As of February 18, 2021, $5 million and $941 million has been repaid by PG&E Corporation and the Utility, respectively.
Chapter 11 Claims Process
PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including asserted litigation claims, trade creditor claims, non-qualified benefit plan claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order.
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order.
The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation and the Utility on or after the Effective Date, including, but not limited to, the following:
•claims arising after the January 29, 2019 Petition Date that constitute administrative expense claims, which will not be discharged pursuant to the Plan, other than allowed administrative expense claims that have been paid in cash or otherwise satisfied in the ordinary course in an amount equal to the allowed amount of such claim on or prior to the Effective Date;
•claims of the Ghost Ship fire litigation (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);
•claims arising out of or based on the 2019 Kincade fire (as defined in Note 14 below), which the California Department of Forestry and Fire Protection has determined was caused by the Utility’s transmission lines; which is currently under investigation by the CPUC and the Sonoma County District Attorney’s Office; and which may also be under investigation by various other entities, including law enforcement agencies; and
•certain FERC refund proceedings, workers’ compensation benefits and environmental claims.
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Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Effective Date, including but not limited to, claims arising from or relating to:
•the purported de-energization securities class action filed in October 2019 and amended to add PG&E Corporation in April 2020. For more information on the filing, see Note 14 below;
•the purported PSPS class action filed in December 2019 and seeking up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid, was dismissed on April 3, 2020, and subsequently appealed on April 6, 2020. For more information on the filing, see Note 15 below; and
•indemnification or contributing claims, including with respect to the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.
In addition, claims continue to be pursued against PG&E Corporation and the Utility and certain of their respective current and former directors and officers as well as certain underwriters, in connection with three purported securities class actions, as further described in Note 14 under the heading “Securities Class Action Litigation.”
Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. Pursuant to the Plan, on and after the Effective Date, the holders of such claims are entitled to pursue their claims against the Reorganized Utility as if the Chapter 11 Cases had not been commenced.
On September 1, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court requesting that the court approve an alternative dispute resolution process for resolving disputed general unsecured claims and appoint a panel of mediators in the process. On September 25, 2020, the court approved the motion and appointed a panel of mediators. The mediators’ role will be to assist various claims through a Standard and Abbreviated Mediation Process.
On October 27, 2020, PG&E Corporation and the Utility filed a motion for entry of an order extending deadline for the reorganized debtors to object to claims, requesting an additional 180 days beyond December 31, 2020 to process claims. On November 17, 2020, the Bankruptcy Court entered an order extending the deadline under the Plan for PG&E Corporation and the Utility to object to claims through and including June 26, 2021 (March 31, 2021, for claims held by the United States), without prejudice to the rights of PG&E Corporation and the Utility to seek additional extensions thereof.
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Reorganization Items, Net
Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $102 million and $400 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2020 as compared to $15 million and $223 million for PG&E Corporation and the Utility, respectively, during 2019. Of the $400 million in cash paid for the Utility’s reorganization items, during the year ended December 31, 2020, $35 million in facility fees related to the Backstop Commitment Letters were recorded to a regulatory asset as they were deemed probable of recovery. Reorganization items, net for the year ended December 31, 2020 include the following:
| Year Ended December 31, 2020 | |||||||||||||||||
| (in millions) | Utility | PG&E Corporation (1) | PG&E Corporation Consolidated | ||||||||||||||
| Debtor-in-possession financing costs | $ | 6 | $ | — | $ | 6 | |||||||||||
Legal and other (2) | 318 | 1,651 | 1,969 | ||||||||||||||
| Interest and other | (14) | (2) | (16) | ||||||||||||||
| Total reorganization items, net | $ | 310 | $ | 1,649 | $ | 1,959 | |||||||||||
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees.
Reorganization items, net from the Petition Date through December 31, 2019 include the following:
| Petition Date Through December 31, 2019 | |||||||||||||||||
| (in millions) | Utility | PG&E Corporation (1) | PG&E Corporation Consolidated | ||||||||||||||
| Debtor-in-possession financing costs | $ | 97 | $ | 17 | $ | 114 | |||||||||||
| Legal and other | 273 | 19 | 292 | ||||||||||||||
| Interest income | (50) | (10) | (60) | ||||||||||||||
| Total reorganization items, net | $ | 320 | $ | 26 | $ | 346 | |||||||||||
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Regulation and Regulated Operations
The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below.
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
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Loss Contingencies
A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.
Revenue Recognition
Revenue from Contracts with Customers
The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.
Regulatory Balancing Account Revenue
The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which generally occur every three or four years. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
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The following table presents the Utility’s revenues disaggregated by type of customer:
| Year Ended | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| Electric | |||||||||||
| Revenue from contracts with customers | |||||||||||
| Residential | $ | 5,523 | $ | 4,847 | |||||||
| Commercial | 4,722 | 4,756 | |||||||||
| Industrial | 1,530 | 1,493 | |||||||||
| Agricultural | 1,471 | 1,106 | |||||||||
| Public street and highway lighting | 69 | 67 | |||||||||
Other (1) | (130) | 168 | |||||||||
| Total revenue from contracts with customers - electric | 13,185 | 12,437 | |||||||||
Regulatory balancing accounts (2) | 673 | 303 | |||||||||
| Total electric operating revenue | $ | 13,858 | $ | 12,740 | |||||||
| Natural gas | |||||||||||
| Revenue from contracts with customers | |||||||||||
| Residential | $ | 2,517 | $ | 2,325 | |||||||
| Commercial | 597 | 605 | |||||||||
| Transportation service only | 1,211 | 1,249 | |||||||||
Other (1) | 61 | 123 | |||||||||
| Total revenue from contracts with customers - gas | 4,386 | 4,302 | |||||||||
Regulatory balancing accounts (2) | 225 | 87 | |||||||||
| Total natural gas operating revenue | 4,611 | 4,389 | |||||||||
| Total operating revenues | $ | 18,469 | $ | 17,129 | |||||||
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.
Cash, Cash Equivalents, and Restricted Cash
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2020, the Utility also holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.
Allowance for Doubtful Accounts Receivable and Credit Losses
PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectible customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
In addition, upon adopting ASU 2016-13, PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. See “Financial Instruments - Credit Losses” below for more information.
Inventories
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
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Emission Allowances
The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.
Property, Plant, and Equipment
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
| Estimated Useful | Balance at December 31, | ||||||||||||||||
| (in millions, except estimated useful lives) | Lives (years) | 2020 | 2019 | ||||||||||||||
Electricity generating facilities (1) | 5 to 75 | $ | 13,751 | $ | 13,189 | ||||||||||||
| Electricity distribution facilities | 10 to 70 | 37,675 | 35,237 | ||||||||||||||
| Electricity transmission facilities | 15 to 75 | 15,556 | 14,281 | ||||||||||||||
| Natural gas distribution facilities | 20 to 60 | 15,133 | 14,236 | ||||||||||||||
| Natural gas transmission and storage facilities | 5 to 66 | 9,002 | 8,452 | ||||||||||||||
| Construction work in progress | 2,757 | 2,675 | |||||||||||||||
| Other | 18 | 18 | |||||||||||||||
| Total property, plant, and equipment | 93,892 | 88,088 | |||||||||||||||
| Accumulated depreciation | (27,756) | (26,453) | |||||||||||||||
Net property, plant, and equipment | $ | 66,136 | $ | 61,635 | |||||||||||||
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.76% in 2020, 3.80% in 2019, and 3.82% in 2018. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $35 million and $140 million during 2020, $55 million and $79 million during 2019, and $53 million and $129 million during 2018.
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Asset Retirement Obligations
The following table summarizes the changes in ARO liability during 2020 and 2019, including nuclear decommissioning obligations:
| (in millions) | 2020 | 2019 | |||||||||
| ARO liability at beginning of year | $ | 5,854 | $ | 5,994 | |||||||
| Liabilities incurred in the current period | 268 | — | |||||||||
| Revision in estimated cash flows | 53 | (376) | |||||||||
| Accretion | 265 | 274 | |||||||||
| Liabilities settled | (28) | (38) | |||||||||
| ARO liability at end of year | $ | 6,412 | $ | 5,854 | |||||||
The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.
Nuclear Decommissioning Obligation
Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.
The total nuclear decommissioning obligation accrued was $5.1 billion and $4.9 billion at December 31, 2020 and 2019, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2020 and 2019.
Disallowance of Plant Costs
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.
Nuclear Decommissioning Trusts
The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility 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. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
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Variable Interest Entities
A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
Consolidated VIE
The SPV is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program (as defined in Note 5 below), the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated.
The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2020 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2020, the SPV has $2.6 billion of net accounts receivable and has outstanding borrowings of $1.0 billion under the Receivables Securitization Program.
Non-Consolidated VIEs
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2020, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2020, it did not consolidate any of them.
Contributions to the Wildfire Fund
On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of December 31, 2020, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.
As of December 31, 2020, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire fund asset, and $5.8 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2020, the Utility recorded amortization and accretion expense of $413 million. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire fund expense in the Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.
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AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation results in the estimated number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Starting with a 5-year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.
Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.
PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ service territories in 2020 for which the cause is currently unknown and which may in the future be determined to be covered by the Wildfire Fund. At December 31, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.
Other Accounting Policies
For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 herein.
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Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:
| (in millions, net of income tax) | Pension Benefits | Other Benefits | Total | ||||||||||||||
| Beginning balance | $ | (22) | $ | 17 | $ | (5) | |||||||||||
| Other comprehensive income before reclassifications: | |||||||||||||||||
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively) | (417) | 170 | (247) | ||||||||||||||
Regulatory account transfer (net of taxes of $155 and $66, respectively) | 400 | (170) | 230 | ||||||||||||||
| Amounts reclassified from other comprehensive income: | |||||||||||||||||
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) | (4) | 10 | 6 | ||||||||||||||
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively) (1) | 2 | (15) | (13) | ||||||||||||||
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1) | 2 | 5 | 7 | ||||||||||||||
| Net current period other comprehensive loss | (17) | — | (17) | ||||||||||||||
| Ending balance | $ | (39) | $ | 17 | $ | (22) | |||||||||||
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.)
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2019 consisted of the following:
| (in millions, net of income tax) | Pension Benefits | Other Benefits | Total | ||||||||||||||
| Beginning balance | $ | (21) | $ | 17 | $ | (4) | |||||||||||
| Other comprehensive income before reclassifications: | |||||||||||||||||
Unrecognized net actuarial loss (net of taxes of $24 and $88, respectively) | 61 | 227 | 288 | ||||||||||||||
Regulatory account transfer (net of taxes of $24 and $88, respectively) | (62) | (227) | (289) | ||||||||||||||
| Amounts reclassified from other comprehensive income: | |||||||||||||||||
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) | (4) | 10 | 6 | ||||||||||||||
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) | 2 | (2) | — | ||||||||||||||
Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) | 2 | (8) | (6) | ||||||||||||||
| Net current period other comprehensive loss | (1) | — | (1) | ||||||||||||||
| Ending balance | $ | (22) | $ | 17 | $ | (5) | |||||||||||
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.)
Recognition of Lease Assets and Liabilities
A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.
The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.
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Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2020 and 2019.
For the years ended December 31, 2020 and 2019, the Utility made total cash payments, including fixed and variable, of $2.5 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.
The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.
At December 31, 2020 and 2019, the Utility’s operating leases had a weighted average remaining lease term of 5.7 years and 5.9 years and a weighted average discount rate of 6.2% and 6.2%, respectively.
The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
| Year Ended December 31, | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| Operating lease fixed cost | $ | 679 | $ | 686 | |||||||
| Operating lease variable cost | 1,852 | 1,778 | |||||||||
| Total operating lease costs | $ | 2,531 | $ | 2,464 | |||||||
At December 31, 2020, the Utility’s future expected operating lease payments were as follows:
| (in millions) | December 31, 2020 | ||||
| 2021 | $ | 624 | |||
| 2022 | 550 | ||||
| 2023 | 257 | ||||
| 2024 | 98 | ||||
| 2025 | 91 | ||||
| Thereafter | 513 | ||||
| Total lease payments | 2,133 | ||||
| Less imputed interest | (397) | ||||
| Total | $ | 1,736 | |||
Recently Adopted Accounting Standards
Intangibles—Goodwill and Other
In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures.
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Financial Instruments—Credit Losses
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses On Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. PG&E Corporation and the Utility adopted the ASU on January 1, 2020.
PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. As of December 31, 2020, expected credit losses of $150 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded at December 31, 2020, $76 million and $10 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively.
Reference Rate Reform
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.
Defined Benefit Plans
In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for defined benefit plans. PG&E Corporation and the Utility adopted the ASU as of December 31, 2020. The adoption of ASU 2018-14 resulted in elimination of the disclosures of (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the (1) aggregate of the service and interest cost components of net periodic benefit costs and (2) benefit obligation for postretirement health care benefits. Additionally, the adoption of this ASU resulted in new disclosures of (i) the weighted-average interest crediting rates for cash balance plans and (ii) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. These amendments have been applied on a retrospective basis to all periods presented. See Note 12 below for further discussion of PG&E Corporation’s and the Utility’s defined benefit pension plans.
Accounting Standards Issued But Not Yet Adopted
Income Taxes
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. This ASU became effective for PG&E Corporation and the Utility on January 1, 2021 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.
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Debt
In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.
NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets
Long-term regulatory assets are comprised of the following:
| Balance at December 31, | Recovery Period | ||||||||||||||||
| (in millions) | 2020 | 2019 | |||||||||||||||
Pension benefits (1) | $ | 2,245 | $ | 1,823 | Indefinitely | ||||||||||||
| Environmental compliance costs | 1,112 | 1,062 | 32 years | ||||||||||||||
Utility retained generation (2) | 181 | 228 | 6 years | ||||||||||||||
| Price risk management | 204 | 124 | 19 years | ||||||||||||||
Unamortized loss, net of gain, on reacquired debt | 49 | 63 | 23 years | ||||||||||||||
Catastrophic event memorandum account (3) | 842 | 656 | 1 - 3 years | ||||||||||||||
Wildfire expense memorandum account (4) | 400 | 423 | 1 - 3 years | ||||||||||||||
Fire hazard prevention memorandum account (5) | 137 | 259 | 1 - 3 years | ||||||||||||||
Fire risk mitigation memorandum account (6) | 66 | 95 | 1 - 3 years | ||||||||||||||
Wildfire mitigation plan memorandum account (7) | 390 | 558 | 1 - 3 years | ||||||||||||||
Deferred income taxes (8) | 908 | 252 | 51 years | ||||||||||||||
Insurance premium costs (9) | 294 | — | 1 - 4 years | ||||||||||||||
Wildfire mitigation balancing account (10) | 156 | — | 1 - 3 years | ||||||||||||||
General rate case memorandum accounts (11) | 376 | — | 1 - 2 years | ||||||||||||||
Vegetation management balancing account (12) | 592 | — | 1 - 3 years | ||||||||||||||
COVID-19 pandemic protection memorandum accounts (13) | 84 | — | TBD years | ||||||||||||||
| Other | 942 | 523 | Various | ||||||||||||||
| Total long-term regulatory assets | $ | 8,978 | $ | 6,066 | |||||||||||||
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval.
(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.
(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval.
(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020. Recovery of WMPMA costs is subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.
(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2020. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
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(11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through the date of the final 2020 GRC decision as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 17 months, beginning March 1, 2021.
(12) The 2020 GRC Decision authorized the Utility to modify the existing one-way VMBA Expense Balancing Account to a two-way balancing account to track the difference between actual and adopted expenses resulting from its routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.
(13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2020, the Utility had recorded an aggregate under-collection of $76 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $8 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.
Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following:
| Balance at December 31, | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
Cost of removal obligations (1) | $ | 6,905 | $ | 6,456 | |||||||
Recoveries in excess of AROs (2) | 458 | 393 | |||||||||
Public purpose programs (3) | 948 | 817 | |||||||||
Employee benefit plans (4) | 995 | 750 | |||||||||
| Other | 1,118 | 854 | |||||||||
Total long-term regulatory liabilities | $ | 10,424 | $ | 9,270 | |||||||
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 11 below.)
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans.
Regulatory Balancing Accounts
The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
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Current regulatory balancing accounts receivable and payable are comprised of the following:
| Receivable Balance at December 31, | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| Electric transmission | $ | — | $ | 9 | |||||||
| Gas distribution and transmission | 102 | 363 | |||||||||
| Energy procurement | 413 | 901 | |||||||||
| Public purpose programs | 292 | 209 | |||||||||
| Fire hazard prevention memorandum account | 121 | — | |||||||||
Fire risk mitigation memorandum account | 33 | — | |||||||||
| Wildfire mitigation plan memorandum account | 161 | — | |||||||||
| Wildfire mitigation balancing account | 27 | — | |||||||||
| General rate case memorandum accounts | 313 | — | |||||||||
| Vegetation management balancing account | 115 | — | |||||||||
| Insurance premium costs | 135 | — | |||||||||
| Other | 289 | 632 | |||||||||
| Total regulatory balancing accounts receivable | $ | 2,001 | $ | 2,114 | |||||||
| Payable Balance at December 31, | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| Electric distribution | $ | 55 | $ | 31 | |||||||
| Electric transmission | 267 | 119 | |||||||||
| Gas distribution and transmission | 76 | 45 | |||||||||
| Energy procurement | 158 | 649 | |||||||||
| Public purpose programs | 410 | 559 | |||||||||
| Other | 279 | 394 | |||||||||
| Total regulatory balancing accounts payable | $ | 1,245 | $ | 1,797 | |||||||
The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. The general rate case memorandum accounts track the difference between the revenue requirements in effect on January 1, 2020 and the revenue requirements authorized by the CPUC in the 2020 GRC Decision in December 2020. The VMBA tracks routine and enhanced vegetation management activities. The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2020, there was $93 million in insurance premium costs recorded in Current regulatory assets.
NOTE 5: DEBT
Debtor-In-Possession Facilities
In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPM, as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto.
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On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.
Credit Facilities
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2020:
| (in millions) | Termination Date | Facility Limit | Borrowings Outstanding | Letters of Credit Outstanding | Facility Availability | ||||||||||||||||||||||||
| Utility revolving credit facility | July 2023 | $ | 3,500 | (1) | $ | 605 | $ | 1,020 | $ | 1,875 | |||||||||||||||||||
| Utility term loan credit facility | Various(2) | 3,000 | 3,000 | — | — | ||||||||||||||||||||||||
| Utility receivables securitization program | October 2022 | 1,000 | 1,000 | — | — | ||||||||||||||||||||||||
| PG&E Corporation revolving credit facility | July 2023 | 500 | — | — | 500 | ||||||||||||||||||||||||
| Total credit facilities | $ | 8,000 | $ | 4,605 | $ | 1,020 | $ | 2,375 | |||||||||||||||||||||
(1) Includes a $1.5 billion letter of credit sublimit.
(2) This includes a $1.5 billion term loan credit facility with a maturity date of June 30, 2021 and a $1.5 billion term loan credit facility with a maturity date of January 1, 2022.
Utility
Utility Revolving Credit Facility
On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM, and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two -year extensions options.
Borrowings under the Utility Revolving Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 1.375% to 2.50% based on the Utility’s credit rating or (2) the base rate plus an applicable margin of 0.375% to 1.50% based on the Utility’s credit rating. In addition to interest on outstanding principal under the Utility Revolving Credit Agreement, the Utility is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.25% to 0.50% per annum depending on the Utility’s credit rating. The Utility Revolving Credit Agreement has a maximum letter of credit sublimit equal to $1.5 billion. The Utility may also pay customary letter of credit fees based on letters of credit issued under the Utility Revolving Credit Agreement.
The Utility’s obligations under the Utility Revolving Credit Agreement are secured by the issuance of a first mortgage bond, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.
The Utility Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, and (4) fundamental changes. In addition, the Utility Revolving Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant.
In the event of a default by the Utility under the Utility Revolving Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the designated agent may, with the consent of the required lenders (or shall upon the request of the required lenders), declare the amounts outstanding under the Utility Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Agreement become payable immediately.
The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary prepayments made by the Utility will not reduce the commitments under the Utility Revolving Credit Agreement.
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Utility Term Loan Credit Facility
On July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent. The credit facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund, in part, transactions contemplated under the Plan.
Borrowings under the Utility Term Loan Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 2.00% with respect to the Utility 364-Day Term Loan Facility and 2.25% with respect to the Utility 18-Month Term Loan Facility, or (2) the base rate plus an applicable margin of 1.00% with respect to the Utility 364-Day Term Loan Facility and 1.25% with respect to the Utility 18-Month Term Loan Facility.
The Utility’s obligations under the Utility Term Loan Credit Agreement are secured by the issuance of first mortgage bonds, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.
The Utility Term Loan Credit Agreement includes usual and customary provisions for term loan agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) fundamental changes, (5) entering into swap agreements and (6) modifications to the Utility’s mortgage indenture. In addition, the Utility Term Loan Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant.
In the event of a default by the Utility under the Utility Term Loan Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Utility Term Loan Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Term Loan Credit Agreement become payable immediately.
The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Agreement (with all outstanding term loans made under the Utility 364-Day Term Loan Facility being paid first), subject to certain exceptions, with 100% of the net cash proceeds of certain securitization transactions. The Utility may voluntarily repay outstanding loans under the Utility Term Loan Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans.
Receivables Securitization Program
On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time.
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The loans under the Receivables Securitization Program bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate. The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events.
The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable.
In general, the proceeds from the sale of the accounts receivable are used by the SPV to pay the purchase price for accounts receivables it acquires from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses.
Although the SPV is a wholly owned consolidated subsidiary of the Utility, the SPV is legally separate from the Utility. The assets of the SPV (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program is accounted for as a secured financing. The pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets.
At December 31, 2020 the Utility had outstanding borrowings of $1.0 billion under the Receivables Securitization Program.
PG&E Corporation
On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two -year extensions at the option of PG&E Corporation. The proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.
Borrowings under the Corporation Revolving Credit Agreement bear interest based on PG&E Corporation’s election of either (1) LIBOR plus an applicable margin of 3.00% to 4.25% based on PG&E Corporation’s credit rating or (2) the base rate plus an applicable margin of 2.00% to 3.25% based on PG&E Corporation’s credit rating. In addition to interest on outstanding principal under the Corporation Revolving Credit Agreement, PG&E Corporation is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.50% to 0.75% per annum depending on PG&E Corporation’s credit rating.
PG&E Corporation’s obligations under the Corporation Revolving Credit Agreement are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.
The Corporation Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) investments, (5) dispositions, (6) changes in the nature of business, (7) transactions with affiliates, (8) burdensome agreements, (9) restricted payments, (10) fundamental changes, (11) use of proceeds, (12) entering into swap agreements and (13) the ability to dispose of common stock of the Utility. In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.
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In the event of a default by PG&E Corporation under the Corporation Revolving Credit Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Corporation Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Agreement become payable immediately.
PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary repayments made by PG&E Corporation will not reduce the commitments under the Corporation Revolving Credit Agreement.
On the Effective Date, PG&E Corporation repaid and terminated $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent.
Other Short-term Borrowings
On November 16, 2020, the Utility completed the sale of $1.45 billion aggregate principal amount of floating rate first mortgage bonds due November 15, 2021. Proceeds from the sale of the mortgage bonds were used for general corporate purposes, including the repayment of borrowings outstanding under the Receivables Securitization Program and borrowings outstanding under the Utility Revolving Credit Facility.
Long-Term Debt
Utility
On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1.0 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2.0 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1.0 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and between the Escrow Agent and the Utility. On July 1, 2020, the net proceeds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.
On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt, as described in the table below.
On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes.
The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first priority lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture.
On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated.
In addition, on July 1, 2020, the Utility obtained a $1.5 billion 18-month secured term loan under the Utility Term Loan Credit Agreement. For more information, see “Credit Facilities” discussion above.
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PG&E Corporation
On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “PG&E Corporation Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”) with JPM, and other lenders from time to time party thereto (collectively, the “Lenders”), JPM, as Administrative Agent and as Collateral Agent. The proceeds of the PG&E Corporation Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation and subsequently released from escrow on the Effective Date pursuant to the Plan.
On February 1, 2021, PG&E Corporation entered into a repricing amendment (the “Repricing Amendment”) with the lenders under the Term Loan Credit Agreement pursuant to which, among other things, the applicable interest rate was reduced.
In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the PG&E Corporation Term Loan in an amount equal to $6.875 million on the last business day of each quarter. The PG&E Corporation Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The PG&E Corporation Term Loan bears interest based, at PG&E Corporation’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. The original LIBOR floor was 1.0% but was reduced to 0.5% on February 1, 2021 in connection with the Repricing Amendment. The original ABR floor was 2.0% but was similarly reduced to 1.5% on February 1, 2021 in connection with the Repricing Amendment. ABR will equal the highest of the following: the prime rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus 1.0%. The applicable margin for LIBOR loans is 3.0% (reduced from 4.5% on February 1, 2021 in connection with the Repricing Amendment) and the applicable margin for ABR loans is 2.0% (reduced from 3.5% on February 1, 2021 in connection with the Repricing Amendment). PG&E Corporation may prepay the PG&E Corporation Term Loan in whole, at any time, and in part, from time to time, without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans; provided, however, that any voluntary prepayment, refinancing or repricing of the PG&E Corporation Term Loan in connection with certain repricing transactions that occur on or prior to August 1, 2021 shall be subject to a prepayment premium of 1.0% of the principal amount of the term loans so prepaid, refinanced or repriced.
The Term Loan Agreement includes usual and customary covenants for loan agreements of this type, including covenants limiting: (1) liens, (2) mergers, (3) sales of all or substantially all of PG&E Corporation’s assets, and (4) sale and leaseback transactions. In addition, the Term Loan Agreement requires that PG&E Corporation maintain ownership, either directly or indirectly, through one or more subsidiaries, of at least 100% of the outstanding common stock of the Utility.
In the event of a default by PG&E Corporation under the Term Loan Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the Administrative Agent may, with the consent of the required Lenders (or upon the request of the required Lenders, shall), declare the amounts outstanding under the Term Loan Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Term Loan Agreement become payable immediately.
On the Effective Date, the obligations under the Term Loan Agreement became secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On July 1, 2020, the net proceeds from the PG&E Corporation Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.
Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (the “2030 Notes,” and together with the 2028 Notes, the “Notes”). The proceeds of the Notes were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and PG&E Corporation. Prior to July 1, 2023, in the case of the 2028 Notes, and prior to July 1, 2025, in the case of the 2030 Notes, (i) PG&E Corporation may redeem all or part of the Notes of the applicable series, on any one or more occasions at a redemption price equal to 100% of the principal amount of Notes of such series to be redeemed, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the redemption date or (ii) PG&E Corporation may redeem up to 40% of the aggregate principal amount of the Notes of the applicable series on any one or more occasions at certain specified redemption prices with the net cash proceeds from certain equity offerings. On or after July 1, 2023, in the case of the 2028 Notes, and July 1, 2025, in the case of the 2030 Notes, PG&E Corporation may redeem the Notes of a series at certain specified redemption prices, plus accrued and unpaid interest thereon, if any, to but not including, the applicable redemption date.
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On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.
On the Effective Date, PG&E Corporation repaid and terminated $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.
The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
| Balance at | |||||||||||||||||||||||
| (in millions) | Contractual Interest Rates (3) | December 31, 2020 | December 31, 2019 | Treatment under Plan on the Effective Date (1) | |||||||||||||||||||
Pre-Petition Debt (2) | |||||||||||||||||||||||
| PG&E Corporation | |||||||||||||||||||||||
| Borrowings under Pre-Petition Credit Facility | |||||||||||||||||||||||
| PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | variable rate (4) | $ | — | $ | 300 | Repaid in cash (14) | |||||||||||||||||
| Other borrowings | |||||||||||||||||||||||
| Term Loan - Stated Maturity: 2020 | variable rate (5) | — | 350 | Repaid in cash (14) | |||||||||||||||||||
| Total PG&E Corporation Pre-Petition Long-Term Debt | — | 650 | |||||||||||||||||||||
| Utility | |||||||||||||||||||||||
| Senior Notes - Stated Maturity: | |||||||||||||||||||||||
| 2020 through 2022 | 2.45% to 4.25% | — | 1,750 | Exchanged (15) | |||||||||||||||||||
| 2023 through 2028 | 2.95% to 4.65% | — | 5,025 | Reinstated (16) | |||||||||||||||||||
| 2034 through 2040 | 5.40% to 6.35% | — | 5,700 | Exchanged (17) | |||||||||||||||||||
| 2041 through 2042 | 3.75% to 4.50% | — | 1,000 | Reinstated (16) | |||||||||||||||||||
| 2043 | 5.13% | — | 500 | Exchanged (17) | |||||||||||||||||||
| 2043 through 2047 | 3.95% to 4.75% | — | 3,550 | Reinstated (16) | |||||||||||||||||||
| Total Pre-Petition Senior Notes | — | 17,525 | |||||||||||||||||||||
| Pollution Control Bonds - Stated Maturity: | |||||||||||||||||||||||
Series 2008 F and 2010 E, due 2026 | 1.75% | — | 100 | Repaid in cash (14) | |||||||||||||||||||
Series 2009 A-B, due 2026 | variable rate (6) | — | 149 | Exchanged (18) | |||||||||||||||||||
Series 1996 C, E, F, 1997 B due 2026 | variable rate (7) | — | 614 | Exchanged (18) | |||||||||||||||||||
| Total Pre-Petition Pollution Control Bonds | — | 863 | |||||||||||||||||||||
| Borrowings under Pre-Petition Credit Facilities | |||||||||||||||||||||||
Utility Revolving Credit Facilities - Stated Maturity: 2022 | variable rate (8) | — | 2,888 | Exchanged (18) | |||||||||||||||||||
| Other borrowings: | |||||||||||||||||||||||
| Term Loan - Stated Maturity: 2019 | variable rate (9) | — | 250 | Exchanged (18) | |||||||||||||||||||
| Total Borrowings under Pre-Petition Credit Facility | — | 3,138 | |||||||||||||||||||||
| Total Utility Pre-Petition Debt | — | 21,526 | |||||||||||||||||||||
| Total PG&E Corporation Consolidated Pre-Petition Debt | $ | — | $ | 22,176 | |||||||||||||||||||
New Long-Term Debt | |||||||||||||||||||||||
| PG&E Corporation | |||||||||||||||||||||||
| Term Loan - Stated Maturity: 2025 | variable rate (10) | $ | 2,709 | $ | — | ||||||||||||||||||
| Senior Secured Notes due 2028 | 5.00% | 1,000 | — | ||||||||||||||||||||
| Senior Secured Notes due 2030 | 5.25% | 1,000 | — | ||||||||||||||||||||
| Unamortized discount, net of premium and debt issuance costs | (85) | — | |||||||||||||||||||||
| Total PG&E Corporation New Long-Term Debt | 4,624 | — | |||||||||||||||||||||
| Utility | |||||||||||||||||||||||
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| Pre-Petition Senior Notes Reinstated as First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
| 2023 through 2028 | 2.95% to 4.65% | 5,025 | — | ||||||||||||||||||||
| 2041 through 2042 | 3.75% to 4.50% | 1,000 | — | ||||||||||||||||||||
| 2043 through 2047 | 3.95% to 4.75% | 3,550 | — | ||||||||||||||||||||
| Unamortized discount, net of premium and debt issuance costs | — | — | |||||||||||||||||||||
| Total Utility Reinstated New Long-Term Debt | 9,575 | — | |||||||||||||||||||||
| Pre-Petition Debt Exchanged for First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
| 2025 | 3.45% | 875 | — | ||||||||||||||||||||
| 2026 | 3.15% | 1,951 | — | ||||||||||||||||||||
| 2028 | 3.75% | 875 | — | ||||||||||||||||||||
| 2030 | 4.55% | 3,100 | — | ||||||||||||||||||||
| 2040 | 4.50% | 1,951 | — | ||||||||||||||||||||
| 2050 | 4.95% | 3,100 | — | ||||||||||||||||||||
| Unamortized discount, net of premium and debt issuance costs | (98) | — | |||||||||||||||||||||
| Total Utility Exchanged New Long-Term Debt | 11,754 | — | |||||||||||||||||||||
| New First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
| 2022 | variable rate (11) | 500 | — | ||||||||||||||||||||
| 2022 | 1.75% | 2,500 | — | ||||||||||||||||||||
| 2027 | 2.10% | 1,000 | — | ||||||||||||||||||||
| 2031 | 2.50% | 2,000 | — | ||||||||||||||||||||
| 2040 | 3.30% | 1,000 | — | ||||||||||||||||||||
| 2050 | 3.50% | 1,925 | — | ||||||||||||||||||||
| Unamortized discount, net of premium and debt issuance costs | (84) | — | |||||||||||||||||||||
| Total Utility New First Mortgage Bonds | 8,841 | — | |||||||||||||||||||||
| Credit Facilities - Stated Maturity: 2022 | |||||||||||||||||||||||
| Receivables securitization program | variable rate (12) | 1,000 | — | ||||||||||||||||||||
18-month Term Loan | variable rate (13) | 1,500 | — | ||||||||||||||||||||
| Unamortized discount, net of premium and debt issuance costs | (6) | — | |||||||||||||||||||||
| Total Utility New Long-Term Debt | 32,664 | — | |||||||||||||||||||||
| Total PG&E Corporation Consolidated New Long-Term Debt | $ | 37,288 | $ | — | |||||||||||||||||||
(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2.
(2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court.
(3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and 2020, respectively.
(4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%.
(5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%.
(6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%.
(7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%.
(8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%.
(9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%.
(10) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 5.50%.
(11) At December 31, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.70%.
(12) At December 31, 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.57%.
(13) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 2.44%.
(14) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020.
(15) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(16) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above.
(17) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(18) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
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Pollution Control Bonds
The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
In accordance with the Plan, on July 1, 2020, the Utility repaid Series 2008 F and 2010 E and exchanged Series 2009 A-B, Series 1996 C, E, F, and 1997 B for first mortgage bonds.
Contractual Repayment Schedule
PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2020 are reflected in the table below:
| (in millions, | |||||||||||||||||||||||||||||||||||||||||
| except interest rates) | 2021 | 2022 | 2023 | 2024 | 2025 | Thereafter | Total | ||||||||||||||||||||||||||||||||||
| PG&E Corporation | |||||||||||||||||||||||||||||||||||||||||
| Average fixed interest rate | — | % | — | % | — | % | — | % | — | % | 5.13 | % | 5.13 | % | |||||||||||||||||||||||||||
| Fixed rate obligations | — | % | — | % | — | % | — | % | — | % | $2,000 | $2,000 | |||||||||||||||||||||||||||||
| Variable interest rate as of December 31, 2020 | 5.50 | % | 5.50 | % | 5.50 | % | 5.50 | % | 5.50 | % | — | % | 5.50 | % | |||||||||||||||||||||||||||
| Variable rate obligations | $ | 28 | $ | 28 | $ | 28 | $ | 28 | $ | 2,625 | $ | — | $ | 2,737 | |||||||||||||||||||||||||||
| Utility | |||||||||||||||||||||||||||||||||||||||||
| Average fixed interest rate | — | % | 1.75 | % | 3.83 | % | 3.60 | % | 3.47 | % | 3.87 | % | 3.66 | % | |||||||||||||||||||||||||||
| Fixed rate obligations | $ | — | $ | 2,500 | $ | 1,175 | $ | 800 | $ | 1,475 | $ | 23,902 | $ | 29,852 | |||||||||||||||||||||||||||
| Variable interest rate as of December 31, 2020 | — | % | various (1) | — | % | — | % | — | % | — | % | various (1) | |||||||||||||||||||||||||||||
Variable rate obligations | $ | — | $ | 3,000 | $ | — | $ | — | $ | — | $ | — | $ | 3,000 | |||||||||||||||||||||||||||
| Total consolidated debt | $ | 28 | $ | 5,528 | $ | 1,203 | $ | 828 | $ | 4,100 | $ | 25,902 | $ | 37,589 | |||||||||||||||||||||||||||
(1) At December 31, 2020, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.57%, 1.70% and 2.44% respectively.
NOTE 6: COMMON STOCK AND SHARE-BASED COMPENSATION
PG&E Corporation had 1,984,678,673 shares of common stock outstanding at December 31, 2020. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2020.
On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. As of the termination date for this agreement, no amounts were outstanding which required repayment.
Increase in Authorized Capitalization
On June 22, 2020, PG&E Corporation filed Amended Articles of Incorporation with the Secretary of State of California which increased the authorized number of shares of common stock to 3.6 billion and the authorized number of shares of preferred stock to 400 million.
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Plan Equity Financings
In connection with emergence from Chapter 11, in July 2020, PG&E Corporation raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments as described below.
PG&E Corporation Investment Agreement
On June 7, 2020, PG&E Corporation entered into an Investment Agreement (the “Investment Agreement”) with certain investors (the “Investors”) relating to the issuance and sale to the Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock. Per the Investment Agreement, the price per share was equal to $9.50 per share, which was the public equity offering price in the Common Stock Offering (as defined below in “Equity Offerings”).
On July 1, 2020, pursuant to the terms of the Investment Agreement, PG&E Corporation issued to the Investors 342.1 million shares of common stock. The Investors and their affiliates have certain customary registration rights with respect to the Shares held by such Investor pursuant to the terms of the Investment Agreement.
Equity Offerings
On June 25, 2020, PG&E Corporation priced (i) the Common Stock Offering of 423.4 million shares of its common stock, and (ii) the concurrent Equity Units Offering of 14.5 million of its Equity Units, for total net proceeds to PG&E Corporation, after deducting the underwriting discounts and before estimated offering expenses payable by the PG&E Corporation, of $3.97 billion and $1.19 billion, respectively.
On June 25, 2020, in connection with the Common Stock Offering, PG&E Corporation entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of several underwriters named in the Common Stock Underwriting Agreement (the “Common Stock Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 423.4 million shares of its common stock to the Common Stock Underwriters. In addition, on June 25, 2020, PG&E Corporation entered into an underwriting agreement (the “Equity Units Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Equity Units Underwriting Agreement (the “Equity Units Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 14.5 million prepaid forward stock purchase contracts (the “Purchase Contracts”) to the Equity Underwriters in order for the Equity Units Underwriters to sell 14.5 million Equity Units.
In connection with the Common Stock Offering and pursuant to the Common Stock Underwriting Agreement, PG&E Corporation granted the underwriters a 30-day over-allotment option to purchase up to an additional 42.3 million shares of common stock. In addition, in connection with the Equity Units Offering and pursuant to the Equity Units Underwriting Agreement, PG&E Corporation also granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.45 million Purchase Contracts to be used by the Equity Units Underwriters to create up to an additional 1.45 million Equity Units (together with the 42.3 million shares of common stock, the “Option Securities”).
The Common Stock Offering and the Equity Units Offering closed on July 1, 2020, and PG&E Corporation issued and sold a total of 423.4 million shares of its common stock and 14.5 million Purchase Contracts for total net proceeds of $5.2 billion. On July 24, 2020, the Equity Units Underwriters exercised in full, the over-allotment option in the Equity Units Underwriting Agreement and on August 3, 2020, PG&E Corporation issued and sold 1.45 million Equity Units to the Equity Units Underwriters (the “Additional Units Issuance”). The prepaid forward stock purchase contract portion of the Equity Units issued in the Equity Units Offering and the Additional Units Issuance represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided herein. The settlement date of the purchase contract is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. The Common Stock Underwriters did not exercise their option to purchase any additional shares of common stock.
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PG&E Corporation applied accounting standards applicable to prepaid forward contracts to purchase common stock in order to determine the proper balance sheet classification for the Equity Units issued and sold during the three months ended, September 30, 2020. The Equity Units are considered a range forward contract, in that the settlement of common stock shares is based on a range of potential settlement outcomes. PG&E Corporation used various inputs, including stock price volatility, and determined that the potential outcomes are predominantly fixed share settlements. As such, PG&E Corporation does not view the Equity Units as an obligation to issue a variable number of shares and has concluded that the Equity Units meet all conditions for equity classification and do not meet any of the other conditions that would result in asset or liability classification. The Equity Units issued and sold are classified as Common stock on PG&E Corporation’s Consolidated Balance Sheet.
Equity Backstop Commitments and Forward Stock Purchase Agreements
See “Equity Financing” in Note 2 above for discussion of the equity backstop commitments which resulted in total net proceeds of $523 million (of which $120.5 million were returned to the Backstop Parties pursuant to the Forward Stock Purchase Agreements, as described below).
In connection with the Additional Units Issuance and pursuant to the terms of the Forward Stock Purchase Agreements, on August 3, 2020, PG&E Corporation (i) redeemed a portion of the rights under the Forward Stock Purchase Agreements to receive shares of Common Stock and returned approximately $120.5 million to the Backstop Parties and (ii) issued and delivered to the Backstop Parties 42.3 million Greenshoe Backstop Shares, representing the unredeemed portion of the Aggregate Greenshoe Backstop Purchase Amount divided by the Settlement Price (without any issuance in respect of fractional shares).
Equity Issuances to the Fire Victim Trust
On the Effective Date, pursuant to the Plan, the Utility entered into the Fire Victim Trust Assignment Agreement, pursuant to which the Utility transferred to the Fire Victim Trust 477 million shares of common stock of PG&E Corporation. As a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement.
Cash Contribution to the Utility Pursuant to the Plan
On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash to the Utility, which used the funds to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein.
Ownership Restrictions in PG&E Corporation’s Amended Articles
Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.
As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
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In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility issued to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. The shares transferred to the Fire Victim Trust were valued at $4.53 billion on the date of transfer, $2.2 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.
In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of December 31, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. PG&E Corporation expects to elect grantor trust treatment, subject to entering into a definitive agreement with the Fire Victim Trust. There can be no assurance that such an agreement will be reached or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur only at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were contributed to the Fire Victim Trust.
Dividends
On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.
On April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s WMP.
On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.
In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.
Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, -year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.
Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of December 31, 2020, it is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.
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Long-Term Incentive Plan
The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. As of the Effective Date, the LTIP was amended to increase the maximum number of shares of PG&E Corporation common stock reserved for issuance under the LTIP from 17 million shares to 47 million (subject to certain adjustments), of which 29,174,205 shares were available for future awards at December 31, 2020.
The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2020:
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Stock Options | $ | 3 | $ | 7 | $ | 10 | |||||||||||
| Restricted stock units | 15 | 21 | 43 | ||||||||||||||
| Performance shares | 17 | 22 | 36 | ||||||||||||||
| Total compensation expense (pre-tax) | $ | 35 | $ | 50 | $ | 89 | |||||||||||
| Total compensation expense (after-tax) | $ | 25 | $ | 35 | $ | 63 | |||||||||||
Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Stock Options
The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2020, $0.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of 0.16 years for PG&E Corporation.
The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method in 2019 was $3.87 per share. No stock options were granted in 2020. The significant assumptions used for shares granted in 2019 were:
| 2019 | |||||
| Expected stock price volatility | 57.00 | % | |||
| Expected annual dividend payment | — | % | |||
| Risk-free interest rate | 1.51% to 1.52% | ||||
| Expected life (years) | 4.5 | ||||
Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.
There was no tax benefit recognized from stock options for the year ended December 31, 2020.
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The following table summarizes stock option activity for PG&E Corporation and the Utility for 2020:
| Number of Stock Options | Weighted Average Grant- Date Fair Value | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||
| Outstanding at January 1 | 4,281,403 | $ | 5.98 | $ | — | ||||||||||||||||||
Granted (1) | 20,065 | 3.87 | — | ||||||||||||||||||||
| Exercised | — | — | — | ||||||||||||||||||||
| Forfeited or expired | (2,080,221) | 3.87 | — | ||||||||||||||||||||
| Outstanding at December 31 | 2,221,247 | 7.45 | 5.33 years | — | |||||||||||||||||||
| Vested or expected to vest at December 31 | 2,215,076 | 7.43 | 5.31 years | — | |||||||||||||||||||
| Exercisable at December 31 | 1,840,893 | $ | 6.86 | 4.93 years | $ | — | |||||||||||||||||
(1) Represents additional payout of existing stock option grants.
Restricted Stock Units
Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2020, 2019, and 2018 was $9.25, $18.57, and $40.92, respectively. The total fair value of restricted stock units that vested during 2020, 2019, and 2018 was $31 million, $42 million, and $41 million, respectively. The tax detriment from restricted stock units that vested in 2020 was $19 million. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2020, $6 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.58 years.
The following table summarizes restricted stock unit activity for 2020:
| Number of Restricted Stock Units | Weighted Average Grant- Date Fair Value | ||||||||||
| Nonvested at January 1 | 1,040,835 | $ | 44.06 | ||||||||
| Granted | 1,007,782 | 9.25 | |||||||||
| Vested | (944,090) | 33.14 | |||||||||
| Forfeited | (214,174) | 15.75 | |||||||||
| Nonvested at December 31 | 890,353 | $ | 23.05 | ||||||||
Performance Shares
Performance shares generally will vest years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a -year performance period or, for a small number of awards, an internal PG&E Corporation metric. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled.
Compensation expense attributable to performance shares is generally recognized ratably over the applicable -year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2020, 2019, and 2018 was $9.62, $15.39, and $36.92 respectively. The tax detriment from performance shares that vested in 2020 was $49 million. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2020, $54 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 2.2 years.
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The following table summarizes activity for performance shares in 2020:
| Number of Performance Shares | Weighted Average Grant- Date Fair Value | ||||||||||
| Nonvested at January 1 | 688,423 | $ | 36.92 | ||||||||
| Granted | 7,951,541 | 9.62 | |||||||||
| Vested | (132,526) | 41.27 | |||||||||
Forfeited (1) | (1,218,656) | 24.38 | |||||||||
| Nonvested at December 31 | 7,288,782 | $ | 9.16 | ||||||||
(1) Includes performance shares that expired with zero value as performance targets were not met.
NOTE 7: PREFERRED STOCK
PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.
The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share. At December 31, 2020 and December 31, 2019, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.
At December 31, 2020, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2020, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid no dividends on preferred stock in 2020, 2019, or 2018.
NOTE 8: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2020, 2019, and 2018.
| Year Ended December 31, | |||||||||||||||||
| (in millions, except per share amounts) | 2020 | 2019 | 2018 | ||||||||||||||
| Loss attributable to common shareholders | $ | (1,318) | $ | (7,656) | $ | (6,851) | |||||||||||
| Weighted average common shares outstanding, basic | 1,257 | 528 | 517 | ||||||||||||||
| Add incremental shares from assumed conversions: | |||||||||||||||||
Employee share-based compensation | — | — | — | ||||||||||||||
| Equity Units | — | — | — | ||||||||||||||
| Weighted average common share outstanding, diluted | 1,257 | 528 | 517 | ||||||||||||||
| Total Loss per common share, diluted | $ | (1.05) | $ | (14.50) | $ | (13.25) | |||||||||||
For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
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NOTE 9: INCOME TAXES
PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.
Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.
PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
| PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| (in millions) | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||
| Current: | |||||||||||||||||||||||||||||||||||
| Federal | $ | (26) | $ | 1 | $ | (5) | $ | (26) | $ | 4 | $ | 5 | |||||||||||||||||||||||
| State | (34) | 101 | (8) | (34) | 94 | (7) | |||||||||||||||||||||||||||||
| Deferred: | |||||||||||||||||||||||||||||||||||
| Federal | 258 | (2,361) | (2,264) | 290 | (2,363) | (2,278) | |||||||||||||||||||||||||||||
| State | 171 | (1,136) | (1,009) | 185 | (1,137) | (1,009) | |||||||||||||||||||||||||||||
| Tax credits | (7) | (5) | (6) | (7) | (5) | (6) | |||||||||||||||||||||||||||||
Income tax provision (benefit) | $ | 362 | $ | (3,400) | $ | (3,292) | $ | 408 | $ | (3,407) | $ | (3,295) | |||||||||||||||||||||||
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The following tables describe net deferred income tax assets and liabilities:
| PG&E Corporation | Utility | ||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||
| (in millions) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
| Deferred income tax assets: | |||||||||||||||||||||||
| Tax carryforwards | $ | 7,641 | $ | 1,390 | $ | 7,529 | $ | 1,308 | |||||||||||||||
| Compensation | 187 | 151 | 109 | 92 | |||||||||||||||||||
Wildfire-related claims (1) | 544 | 6,520 | 544 | 6,520 | |||||||||||||||||||
Operating lease liability | 489 | 642 | 488 | 640 | |||||||||||||||||||
Other (2) | 212 | 112 | 219 | 121 | |||||||||||||||||||
| Total deferred income tax assets | $ | 9,073 | $ | 8,815 | $ | 8,889 | $ | 8,681 | |||||||||||||||
| Deferred income tax liabilities: | |||||||||||||||||||||||
| Property related basis differences | 8,311 | 7,984 | 8,300 | 7,973 | |||||||||||||||||||
| Regulatory balancing accounts | 763 | 381 | 763 | 381 | |||||||||||||||||||
| Debt financing costs | 526 | — | 526 | — | |||||||||||||||||||
| Operating lease right of use asset | 489 | 642 | 488 | 640 | |||||||||||||||||||
Income tax regulatory asset(3) | 254 | 71 | 254 | 71 | |||||||||||||||||||
Other (4) | 128 | 57 | 128 | 58 | |||||||||||||||||||
| Total deferred income tax liabilities | $ | 10,471 | $ | 9,135 | $ | 10,459 | $ | 9,123 | |||||||||||||||
| Total net deferred income tax liabilities | $ | 1,398 | $ | 320 | $ | 1,570 | $ | 442 | |||||||||||||||
(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred on PG&E Corporation’s and the Utility’s service territory over the past several years.
(2) Amounts include benefits, environmental reserve, and customer advances for construction.
(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.
(4) Amount primarily includes an environmental reserve.
The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
| PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
| Federal statutory income tax rate | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | |||||||||||||||||||||||
| Increase (decrease) in income tax rate resulting from: | |||||||||||||||||||||||||||||||||||
State income tax (net of federal benefit) (1) | (15.3) | 7.5 | 7.9 | 19.1 | 7.5 | 7.9 | |||||||||||||||||||||||||||||
Effect of regulatory treatment of fixed asset differences (2) | 39.0 | 2.8 | 3.6 | (44.9) | 2.8 | 3.6 | |||||||||||||||||||||||||||||
| Tax credits | 1.5 | 0.1 | 0.1 | (1.7) | 0.1 | 0.1 | |||||||||||||||||||||||||||||
Bankruptcy and emergence (3) | (82.5) | — | — | 54.1 | — | — | |||||||||||||||||||||||||||||
Other, net (4) | (2.1) | (0.6) | (0.1) | 2.2 | (0.5) | — | |||||||||||||||||||||||||||||
| Effective tax rate | (38.4) | % | 30.8 | % | 32.5 | % | 49.8 | % | 30.9 | % | 32.6 | % | |||||||||||||||||||||||
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2020, 2019, and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) The Utility includes an adjustment for the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust. PG&E Corporation includes the same adjustment as the Utility and a permanent non-deductible equity backstop premium expense. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively, accounts for the remaining difference.
(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019.
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Unrecognized Tax Benefits
The following table reconciles the changes in unrecognized tax benefits:
| PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
| (in millions) | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||
| Balance at beginning of year | $ | 420 | $ | 377 | $ | 349 | $ | 420 | $ | 377 | $ | 349 | |||||||||||||||||||||||
| Reductions for tax position taken during a prior year | (43) | (1) | (27) | (43) | (1) | (27) | |||||||||||||||||||||||||||||
| Additions for tax position taken during the current year | 60 | 44 | 55 | 60 | 44 | 55 | |||||||||||||||||||||||||||||
| Settlements | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Expiration of statute | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Balance at end of year | $ | 437 | $ | 420 | $ | 377 | $ | 437 | $ | 420 | $ | 377 | |||||||||||||||||||||||
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2020 for PG&E Corporation and the Utility was $16 million.
PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months.
Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2020, 2019, and 2018, these amounts were immaterial.
Tax Settlements
PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010.
Tax years after 2007 remain subject to examination by the State of California.
Carryforwards
The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
| (in millions) | December 31, 2020 | Expiration Year | |||||||||
| Federal: | |||||||||||
| Net operating loss carryforward - Pre-2018 | $ | 3,600 | 2031 - 2036 | ||||||||
| Net operating loss carryforward - Post-2017 | 24,887 | N/A | |||||||||
| Tax credit carryforward | 134 | 2029 - 2040 | |||||||||
| State: | |||||||||||
| Net operating loss carryforward | $ | 25,364 | 2039 - 2040 | ||||||||
| Tax credit carryforward | 100 | Various | |||||||||
On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.
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Other Tax Matters
PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2020, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material.
As of the date of this report, PG&E Corporation does not believe that it had undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022.
During June 2020, the State of California enacted AB 85, which increases taxes on corporations over a three-year period beginning in 2020 by suspension of the net operating loss deduction and a limit of $5 million per year on business tax credits. PG&E Corporation and the Utility do not anticipate any material impacts to PG&E Corporation’s Consolidated Financial Statements due to this legislation.
In December 2020, Congress passed, and the President signed into law the Consolidations and Appropriations Act of 2021. PG&E Corporation and the Utility do not expect this legislation to have a material impact to PG&E Corporation’s Consolidated Financial Statements.
See “Ownership Restrictions in PG&E Corporation’s Amended Articles” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 for information on the possible election to treat the Fire Victim Trust as a “grantor trust” for federal income tax purposes.
NOTE 10: DERIVATIVES
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.
Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value.
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Volume of Derivative Activity
The volumes of the Utility’s outstanding derivatives were as follows:
| Contract Volume | ||||||||||||||||||||
| At December 31, | ||||||||||||||||||||
| Underlying Product | Instruments | 2020 | 2019 | |||||||||||||||||
Natural Gas (1) (MMBtus (2)) | Forwards, Futures and Swaps | 146,642,863 | 131,896,159 | |||||||||||||||||
| Options | 14,140,000 | 14,720,000 | ||||||||||||||||||
| Electricity (Megawatt-hours) | Forwards, Futures and Swaps | 9,435,830 | 18,675,852 | |||||||||||||||||
| Options | — | — | ||||||||||||||||||
Congestion Revenue Rights (3) | 266,091,470 | 308,467,999 | ||||||||||||||||||
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Presentation of Derivative Instruments in the Financial Statements
At December 31, 2020, the Utility’s outstanding derivative balances were as follows:
| Commodity Risk | |||||||||||||||||||||||
| (in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||||||||||
| Current assets – other | $ | 33 | $ | — | $ | 115 | $ | 148 | |||||||||||||||
| Other noncurrent assets – other | 136 | — | — | 136 | |||||||||||||||||||
| Current liabilities – other | (38) | — | 15 | (23) | |||||||||||||||||||
| Noncurrent liabilities – other | (204) | — | 10 | (194) | |||||||||||||||||||
| Total commodity risk | $ | (73) | $ | — | $ | 140 | $ | 67 | |||||||||||||||
At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
| Commodity Risk | |||||||||||||||||||||||
| (in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||||||||||
| Current assets – other | $ | 36 | $ | (6) | $ | 4 | $ | 34 | |||||||||||||||
| Other noncurrent assets – other | 130 | (6) | — | 124 | |||||||||||||||||||
| Current liabilities – other | (31) | 6 | 2 | (23) | |||||||||||||||||||
| Noncurrent liabilities – other | (130) | 6 | — | (124) | |||||||||||||||||||
| Total commodity risk | $ | 5 | $ | — | $ | 6 | $ | 11 | |||||||||||||||
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.
Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2020, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
NOTE 11: FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
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•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
•Level 3 – Unobservable inputs which are supported by little or no market activities.
The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
| Fair Value Measurements | |||||||||||||||||||||||||||||
At December 31, 2020 | |||||||||||||||||||||||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Short-term investments | $ | 470 | $ | — | $ | — | $ | — | $ | 470 | |||||||||||||||||||
| Nuclear decommissioning trusts | |||||||||||||||||||||||||||||
| Short-term investments | 27 | — | — | — | 27 | ||||||||||||||||||||||||
| Global equity securities | 2,398 | — | — | — | 2,398 | ||||||||||||||||||||||||
| Fixed-income securities | 924 | 835 | — | — | 1,759 | ||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | — | 25 | ||||||||||||||||||||||||
Total nuclear decommissioning trusts (2) | 3,349 | 835 | — | — | 4,209 | ||||||||||||||||||||||||
| Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
| Electricity | — | 2 | 166 | 2 | 170 | ||||||||||||||||||||||||
| Gas | — | 1 | — | 113 | 114 | ||||||||||||||||||||||||
| Total price risk management instruments | — | 3 | 166 | 115 | 284 | ||||||||||||||||||||||||
| Rabbi trusts | |||||||||||||||||||||||||||||
| Fixed-income securities | — | 106 | — | — | 106 | ||||||||||||||||||||||||
| Life insurance contracts | — | 79 | — | — | 79 | ||||||||||||||||||||||||
| Total rabbi trusts | — | 185 | — | — | 185 | ||||||||||||||||||||||||
| Long-term disability trust | |||||||||||||||||||||||||||||
| Short-term investments | 9 | — | — | — | 9 | ||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | — | 158 | ||||||||||||||||||||||||
| Total long-term disability trust | 9 | — | — | — | 167 | ||||||||||||||||||||||||
| TOTAL ASSETS | $ | 3,828 | $ | 1,023 | $ | 166 | $ | 115 | $ | 5,315 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
| Electricity | $ | — | $ | 1 | $ | 238 | $ | (25) | $ | 214 | |||||||||||||||||||
| Gas | — | 3 | — | — | 3 | ||||||||||||||||||||||||
| TOTAL LIABILITIES | $ | — | $ | 4 | $ | 238 | $ | (25) | $ | 217 | |||||||||||||||||||
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value.
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| Fair Value Measurements | |||||||||||||||||||||||||||||
At December 31, 2019 | |||||||||||||||||||||||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Short-term investments | $ | 1,323 | $ | — | $ | — | $ | — | $ | 1,323 | |||||||||||||||||||
| Nuclear decommissioning trusts | |||||||||||||||||||||||||||||
| Short-term investments | 6 | — | — | — | 6 | ||||||||||||||||||||||||
| Global equity securities | 2,086 | — | — | — | 2,086 | ||||||||||||||||||||||||
| Fixed-income securities | 862 | 728 | — | — | 1,590 | ||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | — | 21 | ||||||||||||||||||||||||
Total nuclear decommissioning trusts (2) | 2,954 | 728 | — | — | 3,703 | ||||||||||||||||||||||||
| Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
| Electricity | — | 2 | 161 | (11) | 152 | ||||||||||||||||||||||||
| Gas | — | 3 | — | 3 | 6 | ||||||||||||||||||||||||
| Total price risk management instruments | — | 5 | 161 | (8) | 158 | ||||||||||||||||||||||||
| Rabbi trusts | |||||||||||||||||||||||||||||
| Fixed-income securities | — | 100 | — | — | 100 | ||||||||||||||||||||||||
| Life insurance contracts | — | 73 | — | — | 73 | ||||||||||||||||||||||||
| Total rabbi trusts | — | 173 | — | — | 173 | ||||||||||||||||||||||||
| Long-term disability trust | |||||||||||||||||||||||||||||
| Short-term investments | 10 | — | — | — | 10 | ||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | — | 156 | ||||||||||||||||||||||||
| Total long-term disability trust | 10 | — | — | — | 166 | ||||||||||||||||||||||||
| TOTAL ASSETS | $ | 4,287 | $ | 906 | $ | 161 | $ | (8) | $ | 5,523 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
| Electricity | 1 | 2 | 156 | (13) | 146 | ||||||||||||||||||||||||
| Gas | — | 2 | — | (1) | 1 | ||||||||||||||||||||||||
| TOTAL LIABILITIES | $ | 1 | $ | 4 | $ | 156 | $ | (14) | $ | 147 | |||||||||||||||||||
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2020 and 2019.
Trust Assets
Assets Measured at Fair Value
In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.
Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.
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Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.
Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.
Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.
Level 3 Measurements and Uncertainty Analysis
Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. See Note 10 above.
| Fair Value at | ||||||||||||||||||||||||||||||||
| (in millions) | At December 31, 2020 | Valuation Technique | Unobservable Input | |||||||||||||||||||||||||||||
| Fair Value Measurement | Assets | Liabilities | Range (1)/Weighted-Average Price (2) | |||||||||||||||||||||||||||||
| Congestion revenue rights | $ | 153 | $ | 74 | Market approach | CRR auction prices | $ (320.25) - 320.25 / 0.30 | |||||||||||||||||||||||||
| Power purchase agreements | $ | 13 | $ | 164 | Discounted cash flow | Forward prices | $ 12.56 - 148.30 / 35.52 | |||||||||||||||||||||||||
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
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| Fair Value at | ||||||||||||||||||||||||||||||||
| (in millions) | At December 31, 2019 | Valuation Technique | Unobservable Input | |||||||||||||||||||||||||||||
| Fair Value Measurement | Assets | Liabilities | Range (1)/Weighted-Average Price (2) | |||||||||||||||||||||||||||||
| Congestion revenue rights | $ | 140 | $ | 44 | Market approach | CRR auction prices | $ (20.20) - 20.20 / 0.28 | |||||||||||||||||||||||||
| Power purchase agreements | $ | 21 | $ | 112 | Discounted cash flow | Forward prices | $ 11.77 - 59.38 / 33.62 | |||||||||||||||||||||||||
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2020 and 2019, respectively:
| Price Risk Management Instruments | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| Asset (liability) balance as of January 1 | $ | 5 | $ | 95 | |||||||
| Net realized and unrealized gains: | |||||||||||
Included in regulatory assets and liabilities or balancing accounts (1) | (77) | (90) | |||||||||
| Asset (liability) balance as of December 31 | $ | (72) | $ | 5 | |||||||
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Financial Instruments
PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2020 and 2019, as they are short-term in nature.
The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
| At December 31, | |||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||
| (in millions) | Carrying Amount | Level 2 Fair Value | Carrying Amount(1) | Level 2 Fair Value(1)(2) | |||||||||||||||||||
| Debt (Note 5) | |||||||||||||||||||||||
PG&E Corporation | $ | 1,901 | $ | 2,175 | $ | — | $ | — | |||||||||||||||
| Utility | 29,664 | 32,632 | 1,500 | 1,500 | |||||||||||||||||||
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5.
(2) The fair value of the Utility pre-petition debt was $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5.
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Nuclear Decommissioning Trust Investments
The following table provides a summary of equity securities and available-for-sale debt securities:
| (in millions) | Amortized Cost | Total Unrealized Gains | Total Unrealized Losses | Total Fair Value | |||||||||||||||||||
| As of December 31, 2020 | |||||||||||||||||||||||
| Nuclear decommissioning trusts | |||||||||||||||||||||||
| Short-term investments | $ | 27 | $ | — | $ | — | $ | 27 | |||||||||||||||
| Global equity securities | 543 | 1,881 | (1) | 2,423 | |||||||||||||||||||
| Fixed-income securities | 1,610 | 152 | (3) | 1,759 | |||||||||||||||||||
Total (1) | $ | 2,180 | $ | 2,033 | $ | (4) | $ | 4,209 | |||||||||||||||
| As of December 31, 2019 | |||||||||||||||||||||||
| Nuclear decommissioning trusts | |||||||||||||||||||||||
| Short-term investments | $ | 6 | $ | — | $ | — | $ | 6 | |||||||||||||||
| Global equity securities | 500 | 1,609 | (2) | 2,107 | |||||||||||||||||||
| Fixed-income securities | 1,505 | 89 | (4) | 1,590 | |||||||||||||||||||
Total (1) | $ | 2,011 | $ | 1,698 | $ | (6) | $ | 3,703 | |||||||||||||||
(1) Represents amounts before deducting $671 million and $530 million at December 31, 2020 and 2019, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of fixed-income securities by contractual maturity is as follows:
| As of | |||||
| (in millions) | December 31, 2020 | ||||
| Less than 1 year | $ | 50 | |||
| 1–5 years | 475 | ||||
| 5–10 years | 403 | ||||
| More than 10 years | 831 | ||||
| Total maturities of fixed-income securities | $ | 1,759 | |||
The following table provides a summary of activity for the fixed-income and equity securities:
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Proceeds from sales and maturities of nuclear decommissioning investments | $ | 1,518 | $ | 956 | $ | 1,412 | |||||||||||
| Gross realized gains on securities | 159 | 69 | 54 | ||||||||||||||
| Gross realized losses on securities | (41) | (14) | (24) | ||||||||||||||
NOTE 12: EMPLOYEE BENEFIT PLANS
Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates.
PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.
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Change in Plan Assets, Benefit Obligations, and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2020 and 2019:
Pension Plan
| (in millions) | 2020 | 2019 | |||||||||
Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of year | $ | 18,547 | $ | 15,312 | |||||||
| Actual return on plan assets | 2,736 | 3,713 | |||||||||
| Company contributions | 343 | 328 | |||||||||
| Benefits and expenses paid | (867) | (806) | |||||||||
| Fair value of plan assets at end of year | $ | 20,759 | $ | 18,547 | |||||||
| Change in benefit obligation: | |||||||||||
| Benefit obligation at beginning of year | $ | 20,525 | $ | 17,407 | |||||||
| Service cost for benefits earned | 530 | 443 | |||||||||
| Interest cost | 713 | 758 | |||||||||
Actuarial loss (1) | 2,271 | 2,723 | |||||||||
| Plan amendments | — | — | |||||||||
| Benefits and expenses paid | (867) | (806) | |||||||||
Benefit obligation at end of year (2) | $ | 23,172 | $ | 20,525 | |||||||
| Funded Status: | |||||||||||
| Current liability | $ | (3) | $ | (14) | |||||||
| Noncurrent liability | (2,410) | (1,964) | |||||||||
Net liability at end of year | $ | (2,413) | $ | (1,978) | |||||||
(1) The actuarial losses for the years ended December 31, 2020 and 2019 were primarily due to a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was also driven by unfavorable changes in the demographic assumptions used to measure the projected benefit obligation.
(2) PG&E Corporation’s accumulated benefit obligation was $20.7 billion and $18.4 billion at December 31, 2020 and 2019, respectively.
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Postretirement Benefits Other than Pensions
| (in millions) | 2020 | 2019 | |||||||||
| Change in plan assets: | |||||||||||
| Fair value of plan assets at beginning of year | $ | 2,678 | $ | 2,258 | |||||||
| Actual return on plan assets | 379 | 474 | |||||||||
| Company contributions | 26 | 29 | |||||||||
| Plan participant contribution | 81 | 82 | |||||||||
| Benefits and expenses paid | (169) | (165) | |||||||||
| Fair value of plan assets at end of year | $ | 2,995 | $ | 2,678 | |||||||
| Change in benefit obligation: | |||||||||||
| Benefit obligation at beginning of year | $ | 1,832 | $ | 1,745 | |||||||
| Service cost for benefits earned | 61 | 56 | |||||||||
| Interest cost | 63 | 76 | |||||||||
Actuarial (gain) loss (1) | (14) | 22 | |||||||||
| Benefits and expenses paid | (149) | (150) | |||||||||
| Federal subsidy on benefits paid | 3 | 2 | |||||||||
| Plan participant contributions | 80 | 81 | |||||||||
| Benefit obligation at end of year | $ | 1,876 | $ | 1,832 | |||||||
Funded Status: (2) | |||||||||||
| Noncurrent asset | $ | 1,153 | $ | 879 | |||||||
| Noncurrent liability | (34) | (33) | |||||||||
| Net asset at end of year | $ | 1,119 | $ | 846 | |||||||
(1) The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was primarily due to a decrease in the discount rate used to measure the projected benefit obligation, offset by favorable changes in the demographic assumptions and the elimination of excise tax.
(2) At December 31, 2020 and 2019, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $377 million and $343 million as of December 31, 2020, and $337 million and $305 million as of December 31, 2019, respectively.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Net Periodic Benefit Cost
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.
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Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:
Pension Plan
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Service cost for benefits earned (1) | $ | 530 | $ | 443 | $ | 514 | |||||||||||
| Interest cost | 713 | 758 | 687 | ||||||||||||||
| Expected return on plan assets | (1,044) | (906) | (1,021) | ||||||||||||||
| Amortization of prior service cost | (6) | (6) | (6) | ||||||||||||||
| Amortization of net actuarial loss | 3 | 3 | 5 | ||||||||||||||
| Net periodic benefit cost | 196 | 292 | 179 | ||||||||||||||
Less: transfer to regulatory account (2) | 136 | 42 | 157 | ||||||||||||||
| Total expense recognized | $ | 332 | $ | 334 | $ | 336 | |||||||||||
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
Postretirement Benefits Other than Pensions
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Service cost for benefits earned (1) | $ | 61 | $ | 56 | $ | 66 | |||||||||||
| Interest cost | 63 | 76 | 69 | ||||||||||||||
| Expected return on plan assets | (138) | (123) | (130) | ||||||||||||||
| Amortization of prior service cost | 14 | 14 | 14 | ||||||||||||||
| Amortization of net actuarial loss | (21) | (3) | (5) | ||||||||||||||
| Net periodic benefit cost | $ | (21) | $ | 20 | $ | 14 | |||||||||||
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Accumulated Other Comprehensive Income
PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).
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Valuation Assumptions
The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
| Pension Plan | PBOP Plans | ||||||||||||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
| Discount rate | 2.77 | % | 3.46 | % | 4.35 | % | 2.67 - 2.80% | 3.37 - 3.47% | 4.29 - 4.37% | ||||||||||||||||||||||||||
| Rate of future compensation increases | 3.80 | % | 3.90 | % | 3.90 | % | N/A | N/A | N/A | ||||||||||||||||||||||||||
| Expected return on plan assets | 5.10 | % | 5.70 | % | 6.00 | % | 3.10 - 6.10% | 3.50 - 6.60% | 3.60 - 6.80% | ||||||||||||||||||||||||||
| Interest crediting rate for cash balance plan | 1.95 | % | 2.11 | % | 3.15 | % | N/A | N/A | N/A | ||||||||||||||||||||||||||
The assumed health care cost trend rate as of December 31, 2020 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond.
Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 5.1% compares to a ten-year actual return of 9.6%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 835 Aa-grade non-callable bonds at December 31, 2020. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
Investment Policies and Strategies
The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.
The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios.
Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.
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The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
| Pension Plan | PBOP Plans | ||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Global equity securities | 30 | % | 30 | % | 29 | % | 36 | % | 28 | % | 33 | % | |||||||||||||||||||||||
| Absolute return | 2 | % | 2 | % | 5 | % | 1 | % | 2 | % | 3 | % | |||||||||||||||||||||||
| Real assets | 8 | % | 8 | % | 8 | % | 5 | % | 8 | % | 6 | % | |||||||||||||||||||||||
| Fixed-income securities | 60 | % | 60 | % | 58 | % | 58 | % | 62 | % | 58 | % | |||||||||||||||||||||||
| Total | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | |||||||||||||||||||||||
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.
Fair Value Measurements
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2020 and 2019.
| Fair Value Measurements | |||||||||||||||||||||||||||||||||||||||||||||||
| At December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||
| Pension Plan: | |||||||||||||||||||||||||||||||||||||||||||||||
| Short-term investments | $ | 334 | $ | 408 | $ | — | $ | 742 | $ | 613 | $ | 231 | $ | — | $ | 844 | |||||||||||||||||||||||||||||||
| Global equity securities | 1,875 | — | — | 1,875 | 1,650 | — | — | 1,650 | |||||||||||||||||||||||||||||||||||||||
| Absolute Return | 1 | 1 | — | 2 | — | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||||
| Real assets | 517 | — | — | 517 | 548 | 1 | — | 549 | |||||||||||||||||||||||||||||||||||||||
| Fixed-income securities | 2,467 | 7,154 | 12 | 9,633 | 2,227 | 6,413 | 15 | 8,655 | |||||||||||||||||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | 8,224 | — | — | — | 6,937 | |||||||||||||||||||||||||||||||||||||||
| Total | $ | 5,194 | $ | 7,563 | $ | 12 | $ | 20,993 | $ | 5,038 | $ | 6,646 | $ | 15 | $ | 18,636 | |||||||||||||||||||||||||||||||
| PBOP Plans: | |||||||||||||||||||||||||||||||||||||||||||||||
| Short-term investments | $ | 37 | $ | — | $ | — | $ | 37 | $ | 37 | $ | — | $ | — | $ | 37 | |||||||||||||||||||||||||||||||
| Global equity securities | 173 | — | — | 173 | 151 | — | — | 151 | |||||||||||||||||||||||||||||||||||||||
| Real assets | 54 | — | — | 54 | 58 | — | — | 58 | |||||||||||||||||||||||||||||||||||||||
| Fixed-income securities | 481 | 715 | 1 | 1,197 | 193 | 875 | 1 | 1,069 | |||||||||||||||||||||||||||||||||||||||
| Assets measured at NAV | — | — | — | 1,549 | — | — | — | 1,373 | |||||||||||||||||||||||||||||||||||||||
| Total | $ | 745 | $ | 715 | $ | 1 | $ | 3,010 | $ | 439 | $ | 875 | $ | 1 | $ | 2,688 | |||||||||||||||||||||||||||||||
| Total plan assets at fair value | $ | 24,003 | $ | 21,324 | |||||||||||||||||||||||||||||||||||||||||||
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $249 million and other net liabilities of $99 million at December 31, 2020 and 2019, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.
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Short-Term Investments
Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.
Global Equity securities
The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.
Real Assets
The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.
Fixed-Income securities
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Assets Measured at NAV Using Practical Expedient
Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed.
Transfers Between Levels
No material transfers between levels occurred in the years ended December 31, 2020 and 2019.
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Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2020 and 2019:
| (in millions) | |||||
For the year ended December 31, 2020 | Fixed-Income | ||||
| Balance at beginning of year | $ | 15 | |||
| Actual return on plan assets: | |||||
| Relating to assets still held at the reporting date | 2 | ||||
| Relating to assets sold during the period | (3) | ||||
| Purchases, issuances, sales, and settlements: | |||||
| Purchases | 11 | ||||
| Settlements | (13) | ||||
| Balance at end of year | $ | 12 | |||
| (in millions) | |||||
For the year ended December 31, 2019 | Fixed-Income | ||||
| Balance at beginning of year | $ | 8 | |||
| Actual return on plan assets: | |||||
| Relating to assets still held at the reporting date | — | ||||
| Relating to assets sold during the period | — | ||||
| Purchases, issuances, sales, and settlements: | |||||
| Purchases | 11 | ||||
| Settlements | (4) | ||||
| Balance at end of year | $ | 15 | |||
There were no material transfers out of Level 3 in 2020 and 2019.
Cash Flow Information
Employer Contributions
PG&E Corporation and the Utility contributed $343 million to the pension benefit plans and $26 million to the other benefit plans in 2020. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2020. The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2021.
Benefits Payments and Receipts
As of December 31, 2020, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
| (in millions) | Pension Plan | PBOP Plans | Federal Subsidy | ||||||||||||||
| 2021 | 831 | 85 | (6) | ||||||||||||||
| 2022 | 913 | 89 | (6) | ||||||||||||||
| 2023 | 948 | 92 | (6) | ||||||||||||||
| 2024 | 980 | 93 | (7) | ||||||||||||||
| 2025 | 1,009 | 95 | (7) | ||||||||||||||
| Thereafter in the succeeding five years | 5,375 | 471 | (41) | ||||||||||||||
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There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.
Retirement Savings Plan
PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $119 million, $109 million, and $105 million in 2020, 2019, and 2018, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
The Utility’s significant related party transactions were:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2020 | 2019 | 2018 | ||||||||||||||
| Utility revenues from: | |||||||||||||||||
| Administrative services provided to PG&E Corporation | $ | 3 | $ | 4 | $ | 4 | |||||||||||
| Utility expenses from: | |||||||||||||||||
| Administrative services received from PG&E Corporation | $ | 108 | $ | 107 | $ | 94 | |||||||||||
| Utility employee benefit due to PG&E Corporation | 34 | 42 | 76 | ||||||||||||||
At December 31, 2020 and 2019, the Utility had receivables of $35 million and $60 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $46 million and $118 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.
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NOTE 14: WILDFIRE-RELATED CONTINGENCIES
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
2015 Butte Fire
In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.
During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire.
2018 Camp Fire and 2017 Northern California Wildfires Background
According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire.
Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.
PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims were satisfied and discharged in accordance with the Plan, as described below.
Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date
Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.
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On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.” On January 15, 2021, the Utility paid approximately $758 million of the $1.35 billion, pursuant to the Tax Benefits Payment Agreement.
On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees were extinguished in the third quarter of 2020.
On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims (as defined below) was satisfied, released and discharged in the third quarter of 2020.
Plan Support Agreements with Public Entities
On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”).
The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”).
These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date.
Restructuring Support Agreement with Holders of Subrogation Claims
On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.
As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date.
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Restructuring Support Agreement with the TCC
On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also included (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation and the Utility and the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments.
As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan was made on the Effective Date.
2019 Kincade Fire
According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.
On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.
The Utility has submitted electric incident reports to the CPUC indicating that:
•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;
•various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time;
•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;
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•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and
•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.
On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.”
Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant.
PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.
Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.
If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.)
In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Accordingly, PG&E Corporation and the Utility recorded a charge for potential losses in connection with the 2019 Kincade fire in the amount of $625 million for the year ended December 31, 2020 (before available insurance).
The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.
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The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided.
PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages.
The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change.
The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete.
As of February 24, 2021, PG&E Corporation and the Utility are aware of 22 complaints on behalf of approximately 504 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. The petition requests that the cases be coordinated in Sonoma County Superior Court. On December 18, 2020, certain plaintiffs filed a brief in support of PG&E Corporation’s and the Utility’s petition. On December 21, 2020, January 4, 2021 and January 27, 2021, certain plaintiffs filed briefs that supported coordination but requested that the cases be coordinated in San Francisco County Superior Court. On February 2, 2021, pursuant to authorization from the California Judicial Council, a judge of the Sonoma County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for April 2, 2021.
In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation or the Utility were found to have been negligent.
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2020 Zogg Fire
According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management.
On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that:
•wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time;
•according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area;
•the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes;
•on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and
•Cal Fire has not issued a determination as to the cause.
The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the 2020 Zogg fire. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties.
Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire and accordingly recorded a pre-tax charge in the amount of $275 million for the quarter ending December 31, 2020 (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.
The aggregate liability of $275 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $275 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal, state, county and local government entities or agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable.
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PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $275 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties.
The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change.
The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $867.5 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for $219 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $275 million probable loss estimate less an initial self-insured retention of $60 million, plus $4 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
As of February 24, 2021, PG&E Corporation and the Utility are aware of six complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court.
In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent.
Loss Recoveries
PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
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Insurance
Insurance Coverage
PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million.
In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, 2020, PG&E Corporation and the Utility had prepaid insurance of $536 million, reflected in Other current assets on the Consolidated Balance Sheets.
Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.
In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter will be required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage.
The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)
Insurance Receivable
PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2020, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $219 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance for the 2015 Butte fire and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.
If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.
The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
| Insurance Receivable (in millions) | 2020 Zogg fire | 2019 Kincade fire | 2018 Camp fire | 2017 Northern California wildfires | 2015 Butte fire | Total | |||||||||||||||||||||||||||||
Balance at December 31, 2019 | $ | — | $ | — | $ | 1,380 | $ | 808 | $ | 50 | $ | 2,238 | |||||||||||||||||||||||
| Accrued insurance recoveries | 219 | 430 | — | — | — | 649 | |||||||||||||||||||||||||||||
| Reimbursements | — | — | (1,380) | (783) | (50) | (2,213) | |||||||||||||||||||||||||||||
Balance at December 31, 2020 | $ | 219 | $ | 430 | $ | — | $ | 25 | $ | — | $ | 674 | |||||||||||||||||||||||
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Regulatory Recovery
On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.
In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.
On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.
On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or five percent of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).
Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust.
Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
Wildfire-Related Derivative Litigation
Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On November 12, 2020, the Trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene.
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On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al. (now captioned Trotter v. PG&E Corp., et al.), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.
On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.
On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al. (now captioned Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.
On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. On November 5, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. On February 24, 2021, the Fire Victim Trust filed an amended complaint, alleging two causes of action for breach of fiduciary duty against certain former officers and directors. The first cause of action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires, and the second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire. PG&E Corporation and the Utility are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021.
On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 7, 2021.
On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al. (now captioned Trotter v. Meserve, et al.), was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.
Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan.
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The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.
Securities Class Action Litigation
Wildfire-Related Class Action
In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.
Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.
On February 22, 2019, a third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.
On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court.
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Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims
Claims against PG&E Corporation and the Utility relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).
While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows:
•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and
•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.
PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.
Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).
The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set.
On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 26, 2020. No hearing date has been set.
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On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviated mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion.
On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility filed their objection to the Renewed 7023 Motion on October 29, 2020. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline set by the Bankruptcy Court as part of the oral decision to resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion, PG&E Corporation and the Utility filed a revised proposed order, which the Bankruptcy Court entered the same day. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion.
De-energization Class Action
On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.
On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action.
On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter.
On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement.
The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.
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Indemnification Obligations
To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors’ and officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases.
District Attorneys’ Offices Investigations
Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.
On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).
Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.
Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022.
On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund.
On January 15, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a Trustee and a Claims Administrator. The Court continued the hearing to August 20, 2021 for a further update.
Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above.
The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information.
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Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.
SEC Investigation
On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.
Wildfire Fund under AB 1054
On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund 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, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.
Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.
On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification.
The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.
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AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics (described above). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.
On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.
As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan.
For additional information on the Wildfire Fund, see Note 3 above.
NOTE 15: OTHER CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation and the Utility have financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
Enforcement Matters
U.S. District Court Matters and Probation
In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
CPUC and FERC Matters
Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire
On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.
As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval.
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Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.
| (in millions) | |||||||||||||||||
Description(1) | Expense | Capital | Total | ||||||||||||||
| Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) | $ | 236 | $ | — | $ | 236 | |||||||||||
Transmission Safety Inspections and Repairs Expense (TO)(2) | 433 | — | 433 | ||||||||||||||
| Vegetation Management Support Costs (FHPMA) | 36 | — | 36 | ||||||||||||||
| 2017 Northern California Wildfires CEMA Expense and Capital (CEMA) | 82 | 66 | 148 | ||||||||||||||
| 2018 Camp Fire CEMA Expense (CEMA) | 435 | — | 435 | ||||||||||||||
| 2018 Camp Fire CEMA Capital for Restoration (CEMA) | — | 253 | 253 | ||||||||||||||
| 2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) | — | 84 | 84 | ||||||||||||||
| Total | $ | 1,222 | $ | 403 | $ | 1,625 | |||||||||||
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
(2) Transmission amounts are under the FERC’s regulatory authority.
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.
The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025.
On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020.
The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan.
As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMA as of December 31, 2020 and intends to record the remaining charges of $46 million in 2021.
On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition.
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Transmission Owner Rate Case Revenue Subject to Refund
The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for TO18, TO19, and TO20, respectively.
On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which the Utility requested rehearing could also impact the revenues recorded for the TO19 and TO20 periods.
On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18.
The Utility is unable to predict the timing or outcome of the FERC’s decisions in the TO18 proceeding.
Other Matters
PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $144 million and $116 million at December 31, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at December 31, 2020. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
PSPS Class Action
On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.
On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code.
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On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that the plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”
On April 6, 2020, the plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020.
On June 8, 2020, the plaintiff filed its opening brief with the District Court. The Utility filed its opposition brief on July 6, 2020. The plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. On October 20, 2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing.
The Utility is unable to determine the timing and outcome of this proceeding.
GT&S Capital Expenditures 2011-2014
On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.
On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.
The Utility is unable to determine the timing and outcome of this proceeding.
CZU Lightning Complex Fire Notices of Violation
Several governmental entities have raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules, the California Coastal Commission alleging violations of the Coastal Act related to unpermitted development in the coastal zone, the Central Coast Regional Water Quality Control Board alleging unpermitted discharge to waters, and the Santa Cruz County Board of Supervisors adopting a resolution to file a complaint with the CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats, and the management of wood debris. The Coastal Commission issued a Notice of Violation letter to the Utility on November 20, 2020, the Central Coast Regional Water Quality Control Board issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued five Notices of Violation through February 8, 2021, and Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues.
Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.
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Environmental Remediation Contingencies
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
| Balance at | |||||||||||
| (in millions) | December 31, 2020 | December 31, 2019 | |||||||||
| Topock natural gas compressor station | $ | 303 | $ | 362 | |||||||
| Hinkley natural gas compressor station | 132 | 138 | |||||||||
Former manufactured gas plant sites owned by the Utility or third parties (1) | 659 | 568 | |||||||||
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) | 111 | 101 | |||||||||
Fossil fuel-fired generation facilities and sites (3) | 96 | 106 | |||||||||
| Total environmental remediation liability | $ | 1,301 | $ | 1,275 | |||||||
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.
The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.
The Utility’s environmental remediation liability at December 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At December 31, 2020, the Utility expected to recover $986 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.
Natural Gas Compressor Station Sites
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
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Topock Site
The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.
Hinkley Site
The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.
Former Manufactured Gas Plants
Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $460 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.
Utility-Owned Generation Facilities and Third-Party Disposal Sites
Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.
Fossil Fuel-Fired Generation Sites
In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance
The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.
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NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.
NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.
In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.
If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million.
Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.8 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.8 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.
The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.
Diablo Canyon Outages
Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator are expected to occur during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions.
If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC.
Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery.
The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC.
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Purchase Commitments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
| Power Purchase Agreements | |||||||||||||||||||||||||||||||||||
| (in millions) | Renewable Energy | Conventional Energy | Other | Natural Gas | Nuclear Fuel | Total | |||||||||||||||||||||||||||||
| 2021 | $ | 2,270 | $ | 582 | $ | 65 | $ | 466 | $ | 64 | $ | 3,447 | |||||||||||||||||||||||
| 2022 | 2,042 | 511 | 62 | 191 | 54 | 2,860 | |||||||||||||||||||||||||||||
| 2023 | 1,997 | 223 | 61 | 158 | 49 | 2,488 | |||||||||||||||||||||||||||||
| 2024 | 1,972 | 72 | 61 | 151 | 47 | 2,303 | |||||||||||||||||||||||||||||
| 2025 | 1,962 | 70 | 61 | 151 | — | 2,244 | |||||||||||||||||||||||||||||
| Thereafter | 21,335 | 281 | 41 | 184 | — | 21,841 | |||||||||||||||||||||||||||||
| Total purchase commitments | $ | 31,578 | $ | 1,739 | $ | 351 | $ | 1,301 | $ | 214 | $ | 35,183 | |||||||||||||||||||||||
Third-Party Power Purchase Agreements
In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.
Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2020, renewable energy contracts expire at various dates between 2021 and 2043.
Conventional Energy Power Purchase Agreements. The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2020, these power purchase agreements expire at various dates between 2021 and 2033.
Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2020, QF contracts in operation expire at various dates between 2021 and 2049. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.
The net costs incurred for all power purchases and electric capacity amounted to $2.9 billion in 2020, $3.0 billion in 2019, and $3.1 billion in 2018.
Natural Gas Supply, Transportation, and Storage Commitments
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2021 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads.
Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.8 billion in 2020, $0.9 billion in 2019, and $0.6 billion in 2018.
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Nuclear Fuel Agreements
The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2021 and 2024 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.
Payments for nuclear fuel amounted to $111 million in 2020, $74 million in 2019, and $73 million in 2018.
Other Commitments
PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2021 and 2052. At December 31, 2020, the future minimum payments related to these commitments were as follows:
| (in millions) | Other Commitments | ||||
| 2021 | $ | 40 | |||
| 2022 | 30 | ||||
| 2023 | 46 | ||||
| 2024 | 65 | ||||
| 2025 | 60 | ||||
| Thereafter | 2,924 | ||||
| Total minimum lease payments | $ | 3,165 | |||
Payments for other commitments amounted to $45 million in 2020, $48 million in 2019, and $43 million in 2018. Certain office facility leases contain escalation clauses requiring annual increases in rent. The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index. There are options to extend these leases for to five years.
One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively. The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively.
Oakland Headquarters Lease
On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.
Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million.
The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.
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The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023.
In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO.
At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
NOTE 16: SUBSEQUENT EVENTS
Sale of Transmission Tower Wireless Licenses
On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.
The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.
In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million, subject to customary adjustments. SBA paid the Utility $954 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period, resulting in initial cash proceeds of $945 million. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement.
The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market potential additional attachment locations on approximately 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.
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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of internal control over financial reporting as of December 31, 2020, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2020.
Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of PG&E Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2021, expressed an unqualified opinion on the Company's internal control over financial reporting.
Emergence from Chapter 11
As discussed in Note 2 to the financial statements, the Company emerged from Chapter 11 on July 1, 2020. Under the plan of reorganization, the Company is required to comply with certain terms and conditions as described in Note 2 to the financial statements.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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Regulation and Regulated Operations—Refer to Notes 3, 4 and 14 to the financial statements
Critical Audit Matter Description
The Company’s subsidiary, Pacific Gas & Electric Company, follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utility Commission (the “CPUC”) or the Federal Energy Regulatory Commission based on its cost of providing service. Pacific Gas & Electric Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. Pacific Gas & Electric Company capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset under GAAP and are recorded at the appropriate amount.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators, and that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount included the following, among others:
•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.
•We read relevant regulatory orders issued by the CPUC for the Company and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.
•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Company’s filings with the CPUC and the filings with the CPUC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
•We evaluated whether the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.
203
Common Stock Ownership Restrictions – Deferred Tax Asset Valuation—Refer to Note 6 to the financial statements
Critical Audit Matter Description
Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit the Company’s ability to use deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). It is more likely than not that the Company has not undergone an ownership change and the Company’s net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
We identified the Company’s conclusion and disclosure that it has not undergone an ownership change as a critical audit matter due to the significant judgments made by management to interpret Section 382 of the Internal Revenue Code. This required the application of a high degree of auditor judgment and the need to involve our tax specialists when performing audit procedures to evaluate the Company’s disclosure.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Company’s conclusion and disclosure that an ownership change did not occur included the following procedures, among others:
•We tested the effectiveness of controls over the review of the analysis and conclusion related to the Company’s determination of whether a change in ownership occurred and the review of disclosure related to this matter.
•With the assistance of our tax specialists, we evaluated the Company’s analysis of whether a change in ownership occurred, including management’s process for interpreting Section 382 of the Internal Revenue Code, the opinion from the Company’s external tax advisor, and determining the aggregate stock ownership change that occurred in conjunction with the Company’s equity financing transactions.
•We tested the key facts in the opinion from the Company’s external tax advisor by comparing them to underlying source information and testing the mathematical accuracy of the calculations.
•We evaluated whether the disclosure appropriately included management’s conclusion that an ownership change did not occur.
Contributions to the Wildfire Fund—Refer to Notes 3 and 14 to the financial statements
Critical Audit Matter Description
On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund (“Wildfire Fund”) that will be available for eligible California 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. The Company accounts for the contributions to the Wildfire Fund similar to prepaid insurance with expense being allocated to periods ratably based on the estimated period of coverage. As of December 31, 2020, the Wildfire Fund asset is $6.3 billion and the related amortization and accretion for the year ended December 31, 2020 is $413 million. AB 1054 did not specify a period of coverage; therefore the Company estimated the useful life using a Monte Carlo simulation.
We identified the Company’s accounting and disclosure for contributions made to the Wildfire Fund as a critical audit matter due to the significant judgments made by management to (1) determine its accounting conclusion related to the initial and annual contributions as there is no relevant explicit guidance for accounting for contributions to a statewide fund and thus accounting guidance must be applied analogously and (2) determine the useful life, including the key assumptions related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve professionals in our firm with expertise in insurance accounting and our actuarial specialists when performing audit procedures to evaluate the Company’s accounting and disclosure for contributions to the Wildfire Fund.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the accounting for contributions to the Wildfire Fund, the key assumptions used by management in developing its estimate for the useful life of the Wildfire Fund asset, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, and the disclosure relating to the Wildfire Fund asset included the following, among others:
•We tested the effectiveness of controls over (1) the accounting for contributions to the Wildfire Fund; (2) the Company’s review of the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data; (3) review of the Monte Carlo simulation methodology used to develop the useful life estimate; and (4) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.
•With the assistance of professionals in our firm having expertise in insurance accounting, we evaluated management’s judgments related to its determination of the accounting for contributions made to the Wildfire Fund.
•With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.
•We evaluated each of management’s key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, by inquiring of management, comparing the assumptions to the relevant source data, which included external publicly available data, including information filed with the Company’s regulator related to wildfire mitigation efforts and information related to historic fire-loss and Company-prepared data. Additionally, we inspected other publicly available information for any evidence that might contradict management’s assertions.
•We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.
Wildfire-Related Contingencies—Refer to Note 14 to the financial statements
Critical Audit Matter Description
The Company has recorded provisions for loss contingencies related to the 2019 Kincade fire and 2020 Zogg fire. The Company has recorded an estimated probable loss of $900 million as of December 31, 2020, which represents the lower end of the range of reasonably possible losses in connection with the fires.
We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Company’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies and related disclosures included the following, among others:
•We tested the effectiveness of controls over (1) the Company’s determination of whether a loss was probable and/or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.
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•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires by inquiring of management and the Company’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness and the data sources utilized to determine the assumption utilized in management’s estimate.
•We read the legal letters from the Company’s external and internal legal counsel regarding known information, and evaluated whether the information therein was consistent with the information obtained in our procedures.
•We evaluated whether the Company’s disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 25, 2021
We have served as the Company’s auditor since 1999.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Pacific Gas and Electric Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Pacific Gas and Electric Company and subsidiaries (the "Utility") as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Utility as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Utility's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2021 expressed an unqualified opinion on the Utility's internal control over financial reporting.
Emergence from Chapter 11
As discussed in Note 2 to the financial statements, the Utility emerged from Chapter 11 on July 1, 2020. Under the plan of reorganization, the Utility is required to comply with certain terms and conditions as described in Note 2 to the financial statements.
Basis for Opinion
These financial statements are the responsibility of the Utility's management. Our responsibility is to express an opinion on the Utility's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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Regulation and Regulated Operations—Refer to Notes 3, 4 and 14 to the financial statements
Critical Audit Matter Description
The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the California Public Utility Commission (the “CPUC”) or the Federal Energy Regulatory Commission based on its cost of providing service. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under accounting principles generally accepted in the United States of America (“GAAP”) for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the likelihood of recovery of incurred costs in current or future rates due in part to the uncertainty related to future decisions by the rate regulators. This required specialized knowledge of accounting for rate regulation and the rate setting process due its inherent complexities and a high degree of auditor judgment when performing audit procedures to evaluate the reasonableness of management’s conclusions that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset under GAAP and are recorded at the appropriate amount.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation related to the uncertainty of future decisions by the rate regulators, and that the costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount included the following, among others:
•We tested the effectiveness of controls over (1) the evaluation of the likelihood of (a) the recovery in future rates of costs deferred as regulatory assets; and (b) regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates; (2) management’s determination that costs approved by a CPUC decision for tracking purposes meet the definition of a regulatory asset and are recorded at the appropriate amount; and (3) the review of disclosures related to these matters.
•We read relevant regulatory orders issued by the CPUC for the Utility and other public utilities in California, procedural filings, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the CPUC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset balances for completeness.
•For regulatory matters in process (e.g., applications for cost recovery), we inspected the Utility’s filings with the CPUC and the filings with the CPUC by intervenors that may impact the Utility’s future rates, for any evidence that might contradict management’s assertions.
•For regulatory assets approved by a CPUC decision for tracking purposes, we selected samples of costs and evaluated whether they met the definition of a regulatory asset by comparing the costs to the description of the costs approved by a CPUC decision and were recorded at the appropriate amount.
•We evaluated whether the Utility’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, were appropriate and consistent with the information obtained in our procedures.
208
Common Stock Ownership Restrictions – Deferred Tax Asset Valuation—Refer to Note 6 to the financial statements
Critical Audit Matter Description
Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit the Utility’s ability to use deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). It is more likely than not that PG&E Corporation has not undergone an ownership change and the Utility’s net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
We identified the conclusion and disclosure that PG&E Corporation has not undergone an ownership change as a critical audit matter due to the significant judgments made by management to interpret Section 382 of the Internal Revenue Code. This required the application of a high degree of auditor judgment and the need to involve our tax specialists when performing audit procedures to evaluate the Utility’s disclosure.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the conclusion and disclosure that an ownership change did not occur included the following procedures, among others:
•We tested the effectiveness of controls over the review of the analysis and conclusion related to the determination of whether a change in ownership occurred and the review of disclosure related to this matter.
•With the assistance of our tax specialists, we evaluated the analysis of whether a change in ownership occurred, including management’s process for interpreting Section 382 of the Internal Revenue Code, the opinion from the external tax advisor, and determining the aggregate stock ownership change that occurred in conjunction with PG&E Corporation’s equity financing transactions.
•We tested the key facts in the opinion from the external tax advisor by comparing them to underlying source information and testing the mathematical accuracy of the calculations.
•We evaluated whether the disclosure appropriately included management’s conclusion that an ownership change did not occur.
Contributions to the Wildfire Fund—Refer to Notes 3 and 14 to the financial statements
Critical Audit Matter Description
On July 12, 2019, the California Governor signed into law Assembly Bill (“AB”) 1054, a bill which provides for the establishment of a statewide fund (“Wildfire Fund”) that will be available for eligible California 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. The Utility accounts for the contributions to the Wildfire Fund similar to prepaid insurance with expense being allocated to periods ratably based on the estimated period of coverage. As of December 31, 2020, the Wildfire Fund asset is $6.3 billion and the related amortization and accretion for the year ended December 31, 2020 is $413 million. AB 1054 did not specify a period of coverage; therefore the Utility estimated the useful life using a Monte Carlo simulation.
We identified the Utility’s accounting and disclosure for contributions made to the Wildfire Fund as a critical audit matter due to the significant judgments made by management to (1) determine its accounting conclusion related to the initial and annual contributions as there is no relevant explicit guidance for accounting for contributions to a statewide fund and thus accounting guidance must be applied analogously and (2) determine the useful life, including the key assumptions related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data. This required the application of a high degree of auditor judgment, extensive audit effort, and the need to involve professionals in our firm with expertise in insurance accounting and our actuarial specialists when performing audit procedures to evaluate the Utility’s accounting and disclosure for contributions to the Wildfire Fund.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the accounting for contributions to the Wildfire Fund, the key assumptions used by management in developing its estimate for the useful life of the Wildfire Fund asset, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, and the disclosure relating to the Wildfire Fund asset included the following, among others:
•We tested the effectiveness of controls over (1) the accounting for contributions to the Wildfire Fund; (2) the Utility’s review of the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data; (3) review of the Monte Carlo simulation methodology used to develop the useful life estimate; and (4) the disclosures related to the Wildfire Fund asset and the key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data.
•With the assistance of professionals in our firm having expertise in insurance accounting, we evaluated management’s judgments related to its determination of the accounting for contributions made to the Wildfire Fund.
•With the assistance of our actuarial specialists, we evaluated the appropriateness of the methodology used to determine the Wildfire Fund asset useful life. This evaluation of the modeling methodology included a detailed assessment of the Monte Carlo simulation.
•We evaluated each of management’s key assumptions to the useful life estimate, including those related to the effectiveness of wildfire mitigation efforts and the period of historic fire-loss data, by inquiring of management, comparing the assumptions to the relevant source data, which included external publicly available data, including information filed with the Utility’s regulator related to wildfire mitigation efforts and information related to historic fire-loss and Utility-prepared data. Additionally, we inspected other publicly available information for any evidence that might contradict management’s assertions.
•We evaluated whether the disclosures were appropriate and consistent with the information obtained in our procedures.
Wildfire-Related Contingencies—Refer to Note 14 to the financial statements
Critical Audit Matter Description
The Utility has recorded provisions for loss contingencies related to the 2019 Kincade fire and 2020 Zogg fire. The Utility has recorded an estimated probable loss of $900 million as of December 31, 2020, which represents the lower end of the range of reasonably possible losses in connection with the fires.
We identified wildfire-related contingencies and the related disclosures as a critical audit matter because (1) of the significant judgments made by management to estimate losses and (2) the outcome of the wildfire-related contingencies materially affects the Utility’s financial position, results of operations, and cash flows. This required the application of a high degree of auditor judgment and extensive audit effort when performing audit procedures to evaluate the reasonableness of management’s estimated losses and disclosure related to wildfire-related contingencies.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s judgments regarding its estimated losses for wildfire-related contingencies and related disclosures included the following, among others:
•We tested the effectiveness of controls over (1) the Utility’s determination of whether a loss was probable and/or reasonably possible; (2) the determination of the significant assumptions, including the information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel that may impact the valuation of the liability; and (3) the disclosures related to the wildfires.
•We evaluated management’s judgments related to whether a loss was probable and/or reasonably possible for the wildfires by inquiring of management and the Utility’s legal counsel regarding the amounts of probable and reasonably possible losses, including the potential impact of information gained through investigations into the cause of the fire, information from claimants, and the advice of legal counsel, and reading external information for any evidence that might contradict management’s assertions.
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•We evaluated the estimation methodology for determining the amount of probable loss through inquiries with management; we tested the significant assumptions used in the valuation of the liability. With the assistance of our real estate valuation specialists, we assessed the appropriateness and the data sources utilized to determine the assumption utilized in management’s estimate.
•We read the legal letters from the Utility’s external and internal legal counsel regarding known information, and evaluated whether the information therein was consistent with the information obtained in our procedures.
We evaluated whether the Utility’s disclosures were appropriate and consistent with the information obtained in our procedures.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 25, 2021
We have served as the Utility’s auditor since 1999.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of PG&E Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Company and our report dated February 25, 2021, expressed an unqualified opinion on those consolidated financial statements and included an emphasis of a matter paragraph regarding the Company’s emergence from Chapter 11.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 25, 2021
212
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Pacific Gas and Electric Company
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Utility and our report dated February 25, 2021, expressed an unqualified opinion on those consolidated financial statements and included an emphasis of a matter paragraph regarding the Utility’s emergence from Chapter 11.
Basis for Opinion
The Utility’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Utility’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Utility in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 25, 2021
213
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCE DISCLOSURE
Not applicable.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, 2020, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the 1934 Act is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management’s report, together with the report of the independent registered public accounting firm, appears in Item 8 of this 2020 Form 10-K under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”
Registered Public Accounting Firm’s Report on Internal Control over Financial Reporting
Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
214
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Information About Our Executive Officers” at the end of Part I of this 2020 Form 10-K. Other information regarding directors will be included under the heading “Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference. Information regarding compliance with Section 16 of the Exchange Act will be included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on the Corporate Governance section of PG&E Corporation’s website (www.pgecorp.com/corp/about-us/corporate-governance.page) and on the Utility’s website (www.pge.com/en_US/about-pge/company-information/company-information.page, under the Corporate Governance tab): (1) the PG&E Corporation’s and the Utility’s code of conduct (which meets the definition of “code of ethics” of Item 406(b) of the SEC Regulation S-K) adopted by PG&E Corporation and the Utility and applicable to their directors and employees, including their respective Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation’s and the Utility’s respective corporate governance guidelines, and (3) key Board committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.
If any amendments are made to, or any waivers are granted with respect to, provisions of the code of conduct adopted by PG&E Corporation and the Utility and that apply to their respective Chief Executive Officer and Presidents, as the case may be, Chief Financial Officers, or Controllers, PG&E Corporation and the Utility will post the amended code of ethics on their websites and will disclose any waivers to the code of conduct in a Current Report on Form 8-K.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
There were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2019 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial experts” as defined by the SEC will be included under the headings “Board Committees and Memberships – Audit Committees” and “Board Committees and Memberships” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information responding to Item 11, for each of PG&E Corporation and the Utility, will be included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2020,” “Grants of Plan-Based Awards -2020,” “Outstanding Equity Awards at Fiscal Year End - 2020,” “Option Exercises and Stock Vested - 2020,” “Pension Benefits - 2020,” “Non-Qualified Deferred Compensation - 2020,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “Compensation of Non-Employee Directors – Director Compensation - 2020” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility is set forth under the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
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Equity Compensation Plan Information(1)
The following table provides information as of December 31, 2020 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
| (a) | (b) | (c) | |||||||||||||||||||||||||||
| Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | ||||||||||||||||||||||||||
| Equity compensation plans approved by shareholders | 20,902,525 | (2) | $ | 40.07 | (3) | 29,174,205 | (4) | ||||||||||||||||||||||
| Equity compensation plans not approved by shareholders | — | — | — | ||||||||||||||||||||||||||
| Total equity compensation plans | 20,902,525 | (2) | $ | 40.07 | (3) | 29,174,205 | (4) | ||||||||||||||||||||||
(1) Subject to Compensation Committee certification
(2) Includes 160 phantom stock units, 904,067 restricted stock units and 17,724,603 performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. For performance shares, amounts reflected in this table assume payout in shares at 200% of target or, for performance shares granted in 2018, reflects the estimated payout percentage of zero percent for performance shares using a total shareholder return metric, 200% for performance shares using a safety metric, and zero percent for performance shares using a financial metric. The actual number of shares issued can range from zero percent to 200% of target depending on achievement of performance objectives. For performance-based stock options, amounts reflected in this table reflect actual payout of 102%. Restricted stock units and performance shares are generally settled in net shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance.
(3) This is the weighted average exercise price for the 2,273,695 options outstanding as of December 31, 2020.
(4) Represents the total number of shares available for issuance under all PG&E Corporation’s equity compensation plans as of December 31, 2020. Stock-based awards granted under these plans include restricted stock units, performance shares, stock options, and phantom stock units. The LTIP, which became effective on May 12, 2014, authorizes up to 17 million shares to be issued pursuant to awards granted under the LTIP. In addition, 5.5 million shares related to awards outstanding under the 2006 long-term incentive plan at December 31, 2013, or awards granted under the 2006 long-term incentive plan from January 1, 2014, through May 11, 2014, were cancelled, forfeited or expired and became available for issuance under the LTIP. A further 30 million shares were authorized for issuance under the LTIP on July 1, 2020, as part of PG&E Corporation’s Chapter 11 Plan of Reorganization
For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information responding to Item 13, for each of PG&E Corporation and the Utility, will be included under the headings “Related Party Transactions” and “Director Diversity and Independence” and “Board Committees and Memberships” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information responding to Item 14, for each of PG&E Corporation and the Utility, will be included under the heading “Information Regarding the Independent Auditor for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders, which information is incorporated herein by reference.
216
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
a. The following documents are filed as a part of this report:
1.The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:
Consolidated Statements of Income for the Years Ended December 31, 2020, 2019, and 2018 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2020 and 2019 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31, 2020, 2019, and 2018 for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2020, 2019, and 2018 for Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Management’s Report on Internal Controls.
Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
2.The following financial statement schedules are filed as part of this report:
Condensed Financial Information of Parent as of December 31, 2020 and 2019 and for the Years Ended December 31, 2020, 2019, and 2018.
Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2020, 2019, and 2018.
3.Exhibits required by Item 601 of Regulation S-K
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| 10.21 | * | |||||||
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| 10.45 | *** | |||||||
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| 10.47 | *** | |||||||
| 10.48 | *** | |||||||
| 10.49 | *** | |||||||
| 10.50 | **** | |||||||
| 10.51 | **** | |||||||
| 10.52 | **** | |||||||
| 10.53 | **** | |||||||
| 10.54 | **** | |||||||
| 10.55 | ***** | |||||||
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225
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| 10.63 | ****** | |||||||
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| 21 | ||||||||
| 23.1 | ||||||||
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| 31.1 | ||||||||
| 31.2 | ******* | |||||||
| 32.1 | ******* | |||||||
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| 101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document | |||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
| 101.LAB | XBRL Taxonomy Extension Labels Linkbase Document | |||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||
| 101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||
230
| * | This Form of Chapter 11 Plan Backstop Commitment Letter is substantially similar in all material respects to each Chapter 11 Plan Backstop Commitment Letter that is otherwise required to be filed as an exhibit, except as to the Backstop Party and the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Chapter 11 Plan Backstop Commitment Letter). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Chapter 11 Plan Backstop Commitment Letter, with a schedule identifying the Chapter 11 Plan Backstop Commitment Letters omitted and setting forth the material details in which each Chapter 11 Plan Backstop Commitment Letter differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Chapter 11 Plan Backstop Commitment Letter so omitted. | |||||||
| ** | In accordance with Item 601(a)(5) of Regulation S-K, certain schedules or similar attachments to this exhibit have been omitted from this filing. Such omitted schedules or similar attachments include information about the Subrogation Claims held by each Consenting Subrogation Creditor. The registrant agrees to furnish a supplemental copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request. | |||||||
| *** | Management contract or compensatory agreement. | |||||||
| **** | The Form of Consent Form is substantially identical in all material respects to each Consent Form that is otherwise required to be filed as an exhibit, except as to the Backstop Party, the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Backstop Commitment Letter) and the amount of such Backstop Party’s Forward Contract Purchase Commitment (as defined in the Consent Form). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Consent Form, with a schedule dated as of June 9, 2020 identifying the Consent Forms omitted and setting forth the material details in which each Consent Form differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted. | |||||||
| ***** | In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request. | |||||||
| ****** | The Form of Forward Stock Purchase Agreement is substantially identical in all material respects to each Forward Stock Purchase Agreement that is otherwise required to be filed as an exhibit, except as to the Purchaser (as defined in the Forward Stock Purchase Agreement), the amount of such Purchaser’s Greenshoe Backstop Purchase Amount and the amount of such Purchaser’s Additional Backstop Premium Shares. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the Purchase Agreements omitted and setting forth the material details in which each Forward Stock Purchase Agreement differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted. | |||||||
| ******* | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report. | |||||||
231
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2020 to be signed on their behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
| PG&E CORPORATION | PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||
| (Registrant) | (Registrant) | ||||||||||
| /s/ PATRICIA K. POPPE | /s/ ADAM L. WRIGHT | ||||||||||
| Patricia K. Poppe | Adam L. Wright | ||||||||||
| By: | Chief Executive Officer | By: | Executive Vice President, Operations and Chief Operating Officer | ||||||||
| Date: | February 25, 2021 | Date: | February 25, 2021 | ||||||||
| Signature | Title | Date | |||||||||||||||
| A. Principal Executive Officers | |||||||||||||||||
| /s/ PATRICIA K. POPPE | Chief Executive Officer | February 25, 2021 | |||||||||||||||
| Patricia K. Poppe | (PG&E Corporation) | ||||||||||||||||
| /s/ ADAM L. WRIGHT | Executive Vice President, Operations and Chief Operating Officer | February 25, 2021 | |||||||||||||||
| Adam L. Wright | (Pacific Gas and Electric Company) | ||||||||||||||||
| /s/ CHRISTOPHER A. FOSTER | Vice President and Interim Chief Financial Officer | February 25, 2021 | |||||||||||||||
| Christopher A. Foster | (PG&E Corporation) | ||||||||||||||||
| /s/ DAVID S. THOMASON | Vice President, Chief Financial Officer, and | February 25, 2021 | |||||||||||||||
| David S. Thomason | Controller (Pacific Gas and Electric Company) | ||||||||||||||||
| B. Principal Accounting Officer | |||||||||||||||||
| /s/ DAVID S. THOMASON | Vice President, Chief Financial Officer, and | February 25, 2021 | |||||||||||||||
| David S. Thomason | Controller (Pacific Gas and Electric Company) | ||||||||||||||||
232
| C. Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted) | |||||||||||||||||
| * | /s/ RAJAT BAHRI | Director | February 25, 2021 | ||||||||||||||
| Rajat Bahri | |||||||||||||||||
| * | /s/ CHERYL F. CAMPBELL | Director | February 25, 2021 | ||||||||||||||
Cheryl F. Campbell | |||||||||||||||||
| * | /s/ KERRY W. COOPER | Director | February 25, 2021 | ||||||||||||||
Kerry W. Cooper | |||||||||||||||||
| * | /s/ JESSICA L. DENECOUR | Director | February 25, 2021 | ||||||||||||||
Jessica L. Denecour | |||||||||||||||||
| * | /s/ MARK E. FERGUSON III | Director | February 25, 2021 | ||||||||||||||
Mark E. Ferguson III | |||||||||||||||||
| * | /s/ ROBERT C. FLEXON | Director | February 25, 2021 | ||||||||||||||
Robert C. Flexon | Chair of the Board (PG&E Corporation) | ||||||||||||||||
| * | /s/ W. CRAIG FUGATE | Director | February 25, 2021 | ||||||||||||||
W. Craig Fugate | |||||||||||||||||
| * | /s/ ARNO L. HARRIS | Director | February 25, 2021 | ||||||||||||||
Arno L. Harris | |||||||||||||||||
| * | /s/ MICHAEL R. NIGGLI, JR. | Director | February 25, 2021 | ||||||||||||||
Michael R. Niggli, Jr. | |||||||||||||||||
| * | /s/ PATRICIA K. POPPE | Director | February 25, 2021 | ||||||||||||||
Patricia K. Poppe | |||||||||||||||||
| * | /s/ DEAN L. SEAVERS | Director | February 25, 2021 | ||||||||||||||
Dean L. Seavers | Chair of the Board (Pacific Gas and Electric Company) | ||||||||||||||||
233
| * | /s/ WILLIAM L. SMITH | Director | February 25, 2021 | ||||||||||||||
William L. Smith | |||||||||||||||||
| * | /s/ OLUWADARA J. TRESEDER | Director | February 25, 2021 | ||||||||||||||
Oluwadara J. Treseder | |||||||||||||||||
| * | /s/ BENJAMIN F. WILSON | Director | February 25, 2021 | ||||||||||||||
Benjamin F. Wilson | |||||||||||||||||
| * | /s/ ADAM L. WRIGHT | Director (Pacific Gas and Electric Company) | February 25, 2021 | ||||||||||||||
Adam L. Wright | |||||||||||||||||
| * | /s/ JOHN M. WOOLARD | Director | February 25, 2021 | ||||||||||||||
| John M. Woolard | |||||||||||||||||
| *By: | /s/ JOHN R. SIMON | February 25, 2021 | |||||||||||||||
| John R. Simon, Attorney-in-Fact | |||||||||||||||||
234
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
| Years Ended December 31, | |||||||||||||||||
| (in millions, except per share amounts) | 2020 | 2019 | 2018 | ||||||||||||||
| Administrative service revenue | $ | 127 | $ | 138 | $ | 90 | |||||||||||
| Operating expenses | (103) | (114) | (91) | ||||||||||||||
| Interest income | — | 1 | 2 | ||||||||||||||
| Interest expense | (149) | (21) | (15) | ||||||||||||||
| Other income (expense) | 13 | 10 | (2) | ||||||||||||||
| Reorganization items, net | (1,649) | (26) | — | ||||||||||||||
| Equity in earnings of subsidiaries | 411 | (7,622) | (6,832) | ||||||||||||||
| Loss before income taxes | (1,350) | (7,634) | (6,848) | ||||||||||||||
| Income tax provision (benefit) | (46) | 8 | 3 | ||||||||||||||
| Net loss | $ | (1,304) | $ | (7,642) | $ | (6,851) | |||||||||||
| Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $7, $0, and $2, at respective dates) | $ | (17) | $ | (1) | $ | 4 | |||||||||||
| Total other comprehensive income (loss) | (17) | (1) | 4 | ||||||||||||||
| Comprehensive Loss | $ | (1,321) | $ | (7,643) | $ | (6,847) | |||||||||||
| Weighted Average Common Shares Outstanding, Basic | 1,257 | 528 | 517 | ||||||||||||||
| Weighted Average Common Shares Outstanding, Diluted | 1,257 | 528 | 513 | ||||||||||||||
| Net loss per common share, basic | $ | (1.05) | $ | (14.50) | $ | (13.25) | |||||||||||
| Net loss per common share, diluted | $ | (1.05) | $ | (14.50) | $ | (13.25) | |||||||||||
235
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED BALANCE SHEETS
| Balance at December 31, | |||||||||||
| (in millions) | 2020 | 2019 | |||||||||
| ASSETS | |||||||||||
| Current Assets | |||||||||||
| Cash and cash equivalents | $ | 223 | $ | 448 | |||||||
| Advances to affiliates | 48 | 120 | |||||||||
| Income taxes receivable | 12 | 12 | |||||||||
| Other current assets | 13 | 11 | |||||||||
| Total current assets | 296 | 591 | |||||||||
| Noncurrent Assets | |||||||||||
| Equipment | 2 | 2 | |||||||||
| Accumulated depreciation | (2) | (2) | |||||||||
| Net equipment | — | — | |||||||||
| Investments in subsidiaries | 25,244 | 5,102 | |||||||||
| Other investments | 186 | 173 | |||||||||
| Operating lease right of use asset | 3 | 6 | |||||||||
| Deferred income taxes | 237 | 187 | |||||||||
| Total noncurrent assets | 25,670 | 5,468 | |||||||||
| Total Assets | $ | 25,966 | $ | 6,059 | |||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||||
| Current Liabilities | |||||||||||
| Long-term debt, classified as current | 28 | — | |||||||||
| Accounts payable – other | 49 | 47 | |||||||||
| Operating lease liabilities | 3 | 3 | |||||||||
| Other current liabilities | 72 | 3 | |||||||||
| Total current liabilities | 152 | 53 | |||||||||
| Noncurrent Liabilities | |||||||||||
| Debtor-in-possession financing | 4,624 | — | |||||||||
| Operating lease liabilities | — | 3 | |||||||||
| Other noncurrent liabilities | 191 | 58 | |||||||||
| Total noncurrent liabilities | 4,815 | 61 | |||||||||
| Liabilities Subject to Compromise | — | 810 | |||||||||
| Common Shareholders’ Equity | |||||||||||
| Common stock | 30,224 | 13,038 | |||||||||
| Reinvested earnings | (9,198) | (7,893) | |||||||||
| Accumulated other comprehensive income (loss) | (27) | (10) | |||||||||
| Total common shareholders’ equity | 20,999 | 5,135 | |||||||||
| Total Liabilities and Shareholders’ Equity | $ | 25,966 | $ | 6,059 | |||||||
236
PG&E CORPORATION
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
| Year ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash Flows from Operating Activities: | |||||||||||||||||
| Net loss | $ | (1,304) | $ | (7,642) | $ | (6,851) | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Stock-based compensation amortization | 28 | 43 | 78 | ||||||||||||||
| Equity in earnings of subsidiaries | (412) | 7,622 | 6,833 | ||||||||||||||
| Deferred income taxes and tax credits-net | (50) | — | (62) | ||||||||||||||
| Reorganization items, net (Note 2) | 1,548 | 11 | — | ||||||||||||||
| Current income taxes receivable/payable | — | 6 | 9 | ||||||||||||||
| Liabilities subject to compromise | 12 | 28 | — | ||||||||||||||
| Other | 97 | (62) | 41 | ||||||||||||||
Net cash provided by (used in) operating activities | (81) | 6 | 48 | ||||||||||||||
| Cash Flows From Investing Activities: | |||||||||||||||||
| Investment in subsidiaries | (12,986) | — | (45) | ||||||||||||||
Net cash used in investing activities | (12,986) | — | (45) | ||||||||||||||
| Cash Flows From Financing Activities: | |||||||||||||||||
| Debtor-in-possession credit facility debt issuance costs | — | (16) | — | ||||||||||||||
| Bridge facility financing fees | (40) | — | — | ||||||||||||||
| Borrowings under revolving credit facility | — | — | 425 | ||||||||||||||
| Repayments under revolving credit facility | — | — | (125) | ||||||||||||||
| Net repayments of commercial paper | — | — | (132) | ||||||||||||||
| Short-term debt financing | — | — | 350 | ||||||||||||||
| Proceeds from issuance of long-term debt | 4,660 | — | — | ||||||||||||||
| Repayment of long-term debt | (664) | — | (350) | ||||||||||||||
| Common stock issued | 7,582 | 85 | 200 | ||||||||||||||
| Equity Units issued | 1,304 | — | — | ||||||||||||||
| Net cash provided by financing activities | 12,842 | 69 | 368 | ||||||||||||||
| Net change in cash and cash equivalents | (225) | 75 | 371 | ||||||||||||||
| Cash and cash equivalents at January 1 | 448 | 373 | 2 | ||||||||||||||
| Cash and cash equivalents at December 31 | $ | 223 | $ | 448 | $ | 373 | |||||||||||
| Supplemental disclosures of cash flow information | |||||||||||||||||
| Cash received (paid) for: | |||||||||||||||||
| Interest, net of amounts capitalized | $ | (105) | $ | (3) | $ | (13) | |||||||||||
| Income taxes, net | — | — | 10 | ||||||||||||||
| Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
| Operating lease liabilities arising from obtaining ROU assets | $ | — | $ | 9 | $ | — | |||||||||||
| Common stock issued in satisfaction of liabilities | 8,276 | — | — | ||||||||||||||
237
PG&E CORPORATION
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2020, 2019, and 2018
| (in millions) | Additions | |||||||||||||||||||||||||||||||
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions (2) | Balance at End of Period | |||||||||||||||||||||||||||
| Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||||||||||||||
| 2020: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 43 | $ | 138 | $ | — | $ | 35 | $ | 146 | ||||||||||||||||||||||
| 2019: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 56 | $ | — | $ | — | $ | 13 | $ | 43 | ||||||||||||||||||||||
| 2018: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 64 | $ | 34 | $ | — | $ | 42 | $ | 56 | ||||||||||||||||||||||
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
238
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2020, 2019, and 2018
| (in millions) | Additions | |||||||||||||||||||||||||||||||
| Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions (2) | Balance at End of Period | |||||||||||||||||||||||||||
| Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||||||||||||||
| 2020: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 43 | $ | 138 | $ | — | $ | 35 | $ | 146 | ||||||||||||||||||||||
| 2019: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 56 | $ | — | $ | — | $ | 13 | $ | 43 | ||||||||||||||||||||||
| 2018: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | 64 | $ | 34 | $ | — | $ | 42 | $ | 56 | ||||||||||||||||||||||
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
239