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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________

FORM 10-K
(Mark One)  
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 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

PCG-20201231_G1.JPG
PCG-20201231_G2.JPG
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
4



5


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

6


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

9


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;
10



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;

11


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;

12


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.


13


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 2,240 
Hydroelectric (2):
  Conventional 16 counties in northern and central California 100  2,655 
  Helms pumped storage Fresno 1,212 
Fossil fuel-fired:
  Colusa Generating Station Colusa 657 
  Gateway Generating Station Contra Costa 580 
  Humboldt Bay Generating Station Humboldt 10  163 
Fuel Cell:
  CSU East Bay Fuel Cell Alameda
  SF State Fuel Cell San Francisco
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 th