(Mark One) | |||||
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the Fiscal Year Ended | |||||
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 | |||||||||||||||||
PG&E CORPORATION | ||||||||||||||||||||
PACIFIC GAS AND ELECTRIC COMPANY |
(Address of principal executive offices) (Zip Code) | (Address of principal executive offices) (Zip Code) | |||||||||||||||||||||||||
(Registrant’s telephone number, including area code) | (Registrant’s telephone number, including area code) |
Securities registered pursuant to Section 12(b) of the Act: | ||||||||
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
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 | ☒ | ||||||||||||||
Pacific Gas and Electric Company: | ☐ | Yes | ☒ |
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 | ☒ | ||||||||||||||
Pacific Gas and Electric Company: | ☐ | Yes | ☒ |
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: | ☒ | ☐ | No | ||||||||||||||
Pacific Gas and Electric Company: | ☒ | ☐ | 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: | ☒ | ☐ | No | ||||||||||||||
Pacific Gas and Electric Company: | ☒ | ☐ | 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 | ||||||||||||||||||||||||
☐ | 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 | $ | ||||
Pacific Gas and Electric Company common stock | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 22, 2021: | ||||||||
PG&E Corporation: | shares | |||||||
Pacific Gas and Electric Company: | shares (wholly owned by PG&E Corporation) |
Designated portions of the Joint Proxy Statement relating to the 2021 Annual Meetings of Shareholders | Part III (Items 10, 11, 12, 13 and 14) |
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 |
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 |
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 |
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 |
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 | ||||
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 |
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 | % | |||||||||||
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 | % | |||||||||||||||
Generation Type | County Location | Number of Units | Net Operating Capacity (MW) | |||||||||||||||||
Nuclear (1): | ||||||||||||||||||||
Diablo Canyon | San Luis Obispo | 2 | 2,240 | |||||||||||||||||
Hydroelectric (2): | ||||||||||||||||||||
Conventional | 16 counties in northern and central California | 100 | 2,655 | |||||||||||||||||
Helms pumped storage | Fresno | 3 | 1,212 | |||||||||||||||||
Fossil fuel-fired: | ||||||||||||||||||||
Colusa Generating Station | Colusa | 1 | 657 | |||||||||||||||||
Gateway Generating Station | Contra Costa | 1 | 580 | |||||||||||||||||
Humboldt Bay Generating Station | Humboldt | 10 | 163 | |||||||||||||||||
Fuel Cell: | ||||||||||||||||||||
CSU East Bay Fuel Cell | Alameda | 1 | 1 | |||||||||||||||||
SF State Fuel Cell | San Francisco | 2 | 2 | |||||||||||||||||
Photovoltaic (3): | Various | 13 | 152 | |||||||||||||||||
Total | 133 | 7,662 | ||||||||||||||||||
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 | |||||||||||
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 | |||||||||||
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 |
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 |
(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) |
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) | |||||||||||||||||||||||||||||||||||||||||||||||
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 | % | |||||||||||
(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 | |||||||||||
(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 | |||||||||||
Year Ended December 31, | |||||||||||||||||
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Net cash provided by (used in) operating activities | $ | (19,047) | $ | 4,810 | $ | 4,704 | |||||||||||
Net cash used in investing activities | (7,748) | (6,378) | (6,564) | ||||||||||||||
Net cash provided by financing activities | 26,070 | 1,395 | 2,708 | ||||||||||||||
Net change in cash, cash equivalents, and restricted cash | $ | (725) | $ | (173) | $ | 848 |
Payment due by period | |||||||||||||||||||||||||||||
(in millions) | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | Total | ||||||||||||||||||||||||
Utility | |||||||||||||||||||||||||||||
Long-term debt (1) | $ | 4,043 | $ | 7,778 | $ | 4,209 | $ | 35,895 | $ | 51,925 | |||||||||||||||||||
Purchase obligations (2) | |||||||||||||||||||||||||||||
Power purchase agreements | 2,917 | 4,896 | 4,198 | 21,657 | 33,668 | ||||||||||||||||||||||||
Natural gas supply, transportation, and storage | 466 | 349 | 302 | 184 | 1,301 | ||||||||||||||||||||||||
Nuclear fuel agreements | 64 | 103 | 47 | — | 214 | ||||||||||||||||||||||||
Pension and other benefits (3) | 342 | 684 | 684 | 342 | 2,052 | ||||||||||||||||||||||||
Operating leases (2) | 42 | 80 | 129 | 3,019 | 3,270 | ||||||||||||||||||||||||
Preferred dividends (4) | 14 | 28 | 28 | — | 70 | ||||||||||||||||||||||||
PG&E Corporation | |||||||||||||||||||||||||||||
Long-term debt (1) | — | — | 2,901 | 2,000 | 4,901 | ||||||||||||||||||||||||
Total Contractual Commitments | $ | 7,888 | $ | 13,918 | $ | 12,498 | $ | 63,097 | $ | 97,401 | |||||||||||||||||||
(in millions) Lines of Business: | Amounts Approved in Final Decision | Increase/ (Decrease) 2019 vs. Final Decision | |||||||||
Electric distribution | $ | 4,800 | $ | 436 | |||||||
Gas distribution | 2,013 | 51 | |||||||||
Electric generation | 2,289 | 98 | |||||||||
Total revenue requirements | $ | 9,102 | $ | 585 | |||||||
Cost Category: | |||||||||||
Operations and maintenance | $ | 2,073 | $ | 128 | |||||||
Customer services | 277 | (61) | |||||||||
Administrative and general | 1,203 | 250 | |||||||||
Less: Revenue credits | (195) | (42) | |||||||||
Franchise fees, taxes other than income, and other adjustments | 214 | 32 | |||||||||
Depreciation (including costs of asset removal), return, and income taxes | 5,530 | 278 | |||||||||
Total revenue requirements | $ | 9,102 | $ | 585 |
(in millions) | Exposure (1) | Number of Wholesale Customers or Counterparties >10% | Net Credit Exposure to Wholesale Customers or Counterparties >10% | ||||||||||||||
December 31, 2020 | $ | 250 | 2 | $ | 57 | ||||||||||||
December 31, 2019 (2) | $ | 381 | 3 | $ | 36 | ||||||||||||
(in millions) | Increase (Decrease) in Assumption | Increase in 2020 Pension Costs | Increase in Projected Benefit Obligation at December 31, 2020 | ||||||||||||||
Discount rate | (0.50) | % | $ | 77 | $ | 1,979 | |||||||||||
Rate of return on plan assets | (0.50) | % | 92 | — | |||||||||||||
Rate of increase in compensation | 0.50 | % | 43 | 435 |
(in millions) | Increase (Decrease) in Assumption | Increase in 2020 Other Postretirement Benefit Costs | Increase in Accumulated Benefit Obligation at December 31, 2020 | ||||||||||||||
Health care cost trend rate | 0.50 | % | $ | 9 | $ | 66 | |||||||||||
Discount rate | (0.50) | % | 11 | 150 | |||||||||||||
Rate of return on plan assets | (0.50) | % | 13 | — |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Operating Revenues | |||||||||||||||||
Electric | $ | $ | $ | ||||||||||||||
Natural gas | |||||||||||||||||
Total operating revenues | |||||||||||||||||
Operating Expenses | |||||||||||||||||
Cost of electricity | |||||||||||||||||
Cost of natural gas | |||||||||||||||||
Operating and maintenance | |||||||||||||||||
Wildfire-related claims, net of insurance recoveries | |||||||||||||||||
Wildfire fund expense | |||||||||||||||||
Depreciation, amortization, and decommissioning | |||||||||||||||||
Total operating expenses | |||||||||||||||||
Operating Income (Loss) | ( | ( | |||||||||||||||
Interest income | |||||||||||||||||
Interest expense | ( | ( | ( | ||||||||||||||
Other income, net | |||||||||||||||||
Reorganization items, net | ( | ( | |||||||||||||||
Loss Before Income Taxes | ( | ( | ( | ||||||||||||||
Income tax provision (benefit) | ( | ( | |||||||||||||||
Net Loss | ( | ( | ( | ||||||||||||||
Preferred stock dividend requirement of subsidiary | |||||||||||||||||
Loss Attributable to Common Shareholders | $ | ( | $ | ( | $ | ( | |||||||||||
Weighted Average Common Shares Outstanding, Basic | |||||||||||||||||
Weighted Average Common Shares Outstanding, Diluted | |||||||||||||||||
Net Loss Per Common Share, Basic | $ | ( | $ | ( | $ | ( | |||||||||||
Net Loss Per Common Share, Diluted | $ | ( | $ | ( | $ | ( |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Net Loss | $ | ( | $ | ( | $ | ( | |||||||||||
Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $ | ( | ( | |||||||||||||||
Total other comprehensive income (loss) | ( | ( | |||||||||||||||
Comprehensive Loss | ( | ( | ( | ||||||||||||||
Preferred stock dividend requirement of subsidiary | |||||||||||||||||
Comprehensive Loss Attributable to Common Shareholders | $ | ( | $ | ( | $ | ( |
Balance at December 31, | |||||||||||
2020 | 2019 | ||||||||||
ASSETS | |||||||||||
Current Assets | |||||||||||
Cash and cash equivalents | $ | $ | |||||||||
Restricted Cash | |||||||||||
Accounts receivable | |||||||||||
Customers (net of allowance for doubtful accounts of $ (includes $ $ | |||||||||||
Accrued unbilled revenue (includes $ | |||||||||||
Regulatory balancing accounts | |||||||||||
Other | |||||||||||
Regulatory assets | |||||||||||
Inventories | |||||||||||
Gas stored underground and fuel oil | |||||||||||
Materials and supplies | |||||||||||
Wildfire fund asset | |||||||||||
Other | |||||||||||
Total current assets | |||||||||||
Property, Plant, and Equipment | |||||||||||
Electric | |||||||||||
Gas | |||||||||||
Construction work in progress | |||||||||||
Other | |||||||||||
Total property, plant, and equipment | |||||||||||
Accumulated depreciation | ( | ( | |||||||||
Net property, plant, and equipment | |||||||||||
Other Noncurrent Assets | |||||||||||
Regulatory assets | |||||||||||
Nuclear decommissioning trusts | |||||||||||
Operating lease right of use asset | |||||||||||
Wildfire fund asset | |||||||||||
Income taxes receivable | |||||||||||
Other | |||||||||||
Total other noncurrent assets | |||||||||||
TOTAL ASSETS | $ | $ |
Balance at December 31, | |||||||||||
2020 | 2019 | ||||||||||
LIABILITIES AND EQUITY | |||||||||||
Current Liabilities | |||||||||||
Short-term borrowings | $ | $ | |||||||||
Long-term debt, classified as current | |||||||||||
Debtor-in-possession financing, classified as current | |||||||||||
Accounts payable | |||||||||||
Trade creditors | |||||||||||
Regulatory balancing accounts | |||||||||||
Other | |||||||||||
Operating lease liabilities | |||||||||||
Disputed claims and customer refunds | |||||||||||
Interest payable | |||||||||||
Wildfire-related claims | |||||||||||
Other | |||||||||||
Total current liabilities | |||||||||||
Noncurrent Liabilities | |||||||||||
Long-term debt (includes $ | |||||||||||
Regulatory liabilities | |||||||||||
Pension and other postretirement benefits | |||||||||||
Asset retirement obligations | |||||||||||
Deferred income taxes | |||||||||||
Operating lease liabilities | |||||||||||
Other | |||||||||||
Total noncurrent liabilities | |||||||||||
Liabilities Subject to Compromise | |||||||||||
Contingencies and Commitments (Notes 14 and 15) | |||||||||||
Equity | |||||||||||
Shareholders' Equity | |||||||||||
Common stock, | |||||||||||
Reinvested earnings | ( | ( | |||||||||
Accumulated other comprehensive loss | ( | ( | |||||||||
Total shareholders' equity | |||||||||||
Noncontrolling Interest - Preferred Stock of Subsidiary | |||||||||||
Total equity | |||||||||||
TOTAL LIABILITIES AND EQUITY | $ | $ |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||
Net loss | $ | ( | $ | ( | $ | ( | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, amortization, and decommissioning | |||||||||||||||||
Allowance for equity funds used during construction | ( | ( | ( | ||||||||||||||
Deferred income taxes and tax credits, net | ( | ( | |||||||||||||||
Reorganization items, net (Note 2) | |||||||||||||||||
Wildfire fund expense | |||||||||||||||||
Disallowed capital expenditures | ( | ||||||||||||||||
Other | |||||||||||||||||
Effect of changes in operating assets and liabilities: | |||||||||||||||||
Accounts receivable | ( | ( | ( | ||||||||||||||
Wildfire-related insurance receivable | ( | ||||||||||||||||
Inventories | ( | ( | |||||||||||||||
Accounts payable | |||||||||||||||||
Wildfire-related claims | ( | ( | |||||||||||||||
Income taxes receivable/payable | ( | ||||||||||||||||
Other current assets and liabilities | ( | ( | |||||||||||||||
Regulatory assets, liabilities, and balancing accounts, net | ( | ( | ( | ||||||||||||||
Liabilities subject to compromise | |||||||||||||||||
Contributions to wildfire fund | ( | ||||||||||||||||
Other noncurrent assets and liabilities | ( | ( | |||||||||||||||
Net cash provided by (used in) operating activities | ( | ||||||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||
Capital expenditures | ( | ( | ( | ||||||||||||||
Proceeds from sales and maturities of nuclear decommissioning trust investments | |||||||||||||||||
Purchases of nuclear decommissioning trust investments | ( | ( | ( | ||||||||||||||
Other | |||||||||||||||||
Net cash used in investing activities | ( | ( | ( | ||||||||||||||
Cash Flows from Financing Activities | |||||||||||||||||
Proceeds from debtor-in-possession credit facility | |||||||||||||||||
Repayments of debtor-in-possession credit facility | ( | ( | |||||||||||||||
Debtor-in-possession credit facility debt issuance costs | ( | ( | |||||||||||||||
Bridge facility financing fees | ( | ||||||||||||||||
Repayment of long-term debt | ( | ( | |||||||||||||||
Borrowings under credit facilities | |||||||||||||||||
Repayments under credit facilities | ( | ( | |||||||||||||||
Credit facilities financing fees | ( | ||||||||||||||||
Net repayments of commercial paper, net of discount of $ | ( | ||||||||||||||||
Short-term debt financing, net of issuance costs of $ | |||||||||||||||||
Short-term debt matured | ( | ||||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $ | |||||||||||||||||
Exchanged debt financing fees | ( | ||||||||||||||||
Common stock issued | |||||||||||||||||
Equity Units issued | |||||||||||||||||
Other | ( | ( | ( | ||||||||||||||
Net cash provided by financing activities | |||||||||||||||||
Net change in cash, cash equivalents, and restricted cash | ( | ( | |||||||||||||||
Cash, cash equivalents, and restricted cash at January 1 | |||||||||||||||||
Cash, cash equivalents, and restricted cash at December 31 | $ | $ | $ | ||||||||||||||
Less: Restricted cash and restricted cash equivalents | ( | ( | ( | ||||||||||||||
Cash and cash equivalents at December 31 | $ | $ | $ |
Supplemental disclosures of cash flow information | |||||||||||||||||
Cash paid for: | |||||||||||||||||
Interest, net of amounts capitalized | $ | ( | $ | ( | $ | ( | |||||||||||
Income taxes, net | ( | ||||||||||||||||
Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
Capital expenditures financed through accounts payable | $ | $ | $ | ||||||||||||||
Operating lease liabilities arising from obtaining ROU assets | |||||||||||||||||
Common stock issued in satisfaction of liabilities |
Common Stock Shares | Common Stock Amount | Reinvested Earnings | Accumulated Other Comprehensive Loss | Total Shareholders' Equity | Non- controlling Interest - Preferred Stock of Subsidiary | Total Equity | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2017 | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||
Net loss | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
Other comprehensive income (loss) | — | — | ( | — | |||||||||||||||||||||||||||||||||||||
Common stock issued, net | — | — | — | ||||||||||||||||||||||||||||||||||||||
Stock-based compensation amortization | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Preferred stock dividend requirement of subsidiary | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
Balance at December 31, 2018 | $ | $ | ( | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||
Net loss | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
Other comprehensive loss | — | — | — | ( | ( | — | ( | ||||||||||||||||||||||||||||||||||
Common stock issued, net | — | — | — | ||||||||||||||||||||||||||||||||||||||
Stock-based compensation amortization | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Balance at December 31, 2019 | $ | $ | ( | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||
Net loss | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
Other comprehensive loss | — | — | — | ( | ( | — | ( | ||||||||||||||||||||||||||||||||||
Common stock issued, net | — | — | — | ||||||||||||||||||||||||||||||||||||||
Equity units issued | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Stock-based compensation amortization | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Balance at December 31, 2020 | $ | $ | ( | $ | ( | $ | $ | $ |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Operating Revenues | |||||||||||||||||
Electric | $ | $ | $ | ||||||||||||||
Natural gas | |||||||||||||||||
Total operating revenues | |||||||||||||||||
Operating Expenses | |||||||||||||||||
Cost of electricity | |||||||||||||||||
Cost of natural gas | |||||||||||||||||
Operating and maintenance | |||||||||||||||||
Wildfire-related claims, net of insurance recoveries | |||||||||||||||||
Wildfire fund expense | |||||||||||||||||
Depreciation, amortization, and decommissioning | |||||||||||||||||
Total operating expenses | |||||||||||||||||
Operating Income (Loss) | ( | ( | |||||||||||||||
Interest income | |||||||||||||||||
Interest expense | ( | ( | ( | ||||||||||||||
Other income, net | |||||||||||||||||
Reorganization items, net | ( | ( | |||||||||||||||
Income (Loss) Before Income Taxes | ( | ( | |||||||||||||||
Income tax provision (benefit) | ( | ( | |||||||||||||||
Net Income (Loss) | ( | ( | |||||||||||||||
Preferred stock dividend requirement | |||||||||||||||||
Income (Loss) Available for Common Stock | $ | $ | ( | $ | ( |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Net Income (Loss) | $ | $ | ( | $ | ( | ||||||||||||
Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $ | ( | ( | |||||||||||||||
Total other comprehensive income (loss) | ( | ( | |||||||||||||||
Comprehensive Income (Loss) | $ | $ | ( | $ | ( |
Balance at December 31, | |||||||||||
2020 | 2019 | ||||||||||
ASSETS | |||||||||||
Current Assets | |||||||||||
Cash and cash equivalents | $ | $ | |||||||||
Restricted Cash | |||||||||||
Accounts receivable | |||||||||||
Customers (net of allowance for doubtful accounts of $ (includes $ | |||||||||||
Accrued unbilled revenue (includes $ | |||||||||||
Regulatory balancing accounts | |||||||||||
Other | |||||||||||
Regulatory assets | |||||||||||
Inventories | |||||||||||
Gas stored underground and fuel oil | |||||||||||
Materials and supplies | |||||||||||
Wildfire fund asset | |||||||||||
Other | |||||||||||
Total current assets | |||||||||||
Property, Plant, and Equipment | |||||||||||
Electric | |||||||||||
Gas | |||||||||||
Construction work in progress | |||||||||||
Other | |||||||||||
Total property, plant, and equipment | |||||||||||
Accumulated depreciation | ( | ( | |||||||||
Net property, plant, and equipment | |||||||||||
Other Noncurrent Assets | |||||||||||
Regulatory assets | |||||||||||
Nuclear decommissioning trusts | |||||||||||
Operating lease right of use asset | |||||||||||
Wildfire fund asset | |||||||||||
Income taxes receivable | |||||||||||
Other | |||||||||||
Total other noncurrent assets | |||||||||||
TOTAL ASSETS | $ | $ |
Balance at December 31, | |||||||||||
2020 | 2019 | ||||||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||||
Current Liabilities | |||||||||||
Short-term borrowings | $ | $ | |||||||||
Debtor-in-possession financing, classified as current | |||||||||||
Accounts payable | |||||||||||
Trade creditors | |||||||||||
Regulatory balancing accounts | |||||||||||
Other | |||||||||||
Operating lease liabilities | |||||||||||
Disputed claims and customer refunds | |||||||||||
Interest payable | |||||||||||
Wildfire-related claims | |||||||||||
Other | |||||||||||
Total current liabilities | |||||||||||
Noncurrent Liabilities | |||||||||||
Long-term debt (includes $ | |||||||||||
Regulatory liabilities | |||||||||||
Pension and other postretirement benefits | |||||||||||
Asset retirement obligations | |||||||||||
Deferred income taxes | |||||||||||
Operating lease liabilities | |||||||||||
Other | |||||||||||
Total noncurrent liabilities | |||||||||||
Liabilities Subject to Compromise | |||||||||||
Contingencies and Commitments (Notes 14 and 15) | |||||||||||
Shareholders' Equity | |||||||||||
Preferred stock | |||||||||||
Common stock, $ outstanding at respective dates | |||||||||||
Additional paid-in capital | |||||||||||
Reinvested earnings | ( | ( | |||||||||
Accumulated other comprehensive income | ( | ||||||||||
Total shareholders' equity | |||||||||||
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | $ |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||
Net income (loss) | $ | $ | ( | $ | ( | ||||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Depreciation, amortization, and decommissioning | |||||||||||||||||
Allowance for equity funds used during construction | ( | ( | ( | ||||||||||||||
Deferred income taxes and tax credits, net | ( | ( | |||||||||||||||
Reorganization items, net (Note 2) | ( | ||||||||||||||||
Wildfire fund expense | |||||||||||||||||
Disallowed capital expenditures | ( | ||||||||||||||||
Other | |||||||||||||||||
Effect of changes in operating assets and liabilities: | |||||||||||||||||
Accounts receivable | ( | ( | ( | ||||||||||||||
Wildfire-related insurance receivable | ( | ||||||||||||||||
Inventories | ( | ( | |||||||||||||||
Accounts payable | ( | ||||||||||||||||
Wildfire-related claims | ( | ( | |||||||||||||||
Income taxes receivable/payable | ( | ||||||||||||||||
Other current assets and liabilities | ( | ( | |||||||||||||||
Regulatory assets, liabilities, and balancing accounts, net | ( | ( | ( | ||||||||||||||
Liabilities subject to compromise | |||||||||||||||||
Contributions to wildfire fund | ( | ||||||||||||||||
Other noncurrent assets and liabilities | ( | ( | |||||||||||||||
Net cash provided by (used in) operating activities | ( | ||||||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||
Capital expenditures | ( | ( | ( | ||||||||||||||
Proceeds from sales and maturities of nuclear decommissioning trust investments | |||||||||||||||||
Purchases of nuclear decommissioning trust investments | ( | ( | ( | ||||||||||||||
Other | |||||||||||||||||
Net cash used in investing activities | ( | ( | ( | ||||||||||||||
Cash Flows from Financing Activities | |||||||||||||||||
Proceeds from debtor-in-possession credit facility | |||||||||||||||||
Repayments of debtor-in-possession credit facility | ( | ( | |||||||||||||||
Debtor-in-possession credit facility debt issuance costs | ( | ( | |||||||||||||||
Bridge facility financing fees | ( | ||||||||||||||||
Repayment of long-term debt | ( | ( | |||||||||||||||
Borrowings under credit facilities | |||||||||||||||||
Repayments under credit facilities | ( | ( | |||||||||||||||
Credit facilities financing fees | ( | ||||||||||||||||
Net repayments of commercial paper, net of discount of $ | ( | ||||||||||||||||
Short-term debt financing, net of issuance costs of $ | |||||||||||||||||
Short-term debt matured | ( | ||||||||||||||||
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $ | |||||||||||||||||
Exchanged debt financing fees | ( | ||||||||||||||||
Equity contribution from PG&E Corporation | |||||||||||||||||
Other | ( | ( | ( | ||||||||||||||
Net cash provided by financing activities | |||||||||||||||||
Net change in cash, cash equivalents, and restricted cash | ( | ( | |||||||||||||||
Cash, cash equivalents, and restricted cash at January 1 | |||||||||||||||||
Cash, cash equivalents, and restricted cash at December 31 | $ | $ | $ | ||||||||||||||
Less: Restricted cash and restricted cash equivalents | ( | ( | ( | ||||||||||||||
Cash and cash equivalents at December 31 | $ | $ | $ |
Supplemental disclosures of cash flow information | |||||||||||||||||
Cash paid for: | |||||||||||||||||
Interest, net of amounts capitalized | $ | ( | $ | ( | $ | ( | |||||||||||
Income taxes, net | ( | ||||||||||||||||
Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
Capital expenditures financed through accounts payable | $ | $ | $ | ||||||||||||||
Operating lease liabilities arising from obtaining ROU assets | |||||||||||||||||
Common stock equity infusion from PG&E Corporation used to satisfy liabilities |
Preferred Stock | Common Stock | Additional Paid-in Capital | Reinvested Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity | ||||||||||||||||||||||||||||||
Balance at December 31, 2017 | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Net loss | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||
Other comprehensive income (loss) | — | — | — | ( | ( | ||||||||||||||||||||||||||||||
Equity contribution | — | — | — | — | |||||||||||||||||||||||||||||||
Preferred stock dividend | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||
Balance at December 31, 2018 | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||
Net loss | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||
Other comprehensive income | — | — | — | — | |||||||||||||||||||||||||||||||
Balance at December 31, 2019 | $ | $ | $ | $ | ( | $ | $ | ||||||||||||||||||||||||||||
Net income | — | — | — | — | |||||||||||||||||||||||||||||||
Other comprehensive loss | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||
Equity contribution | — | — | — | — | |||||||||||||||||||||||||||||||
Balance at December 31, 2020 | $ | $ | $ | $ | ( | $ | ( | $ |
(in millions) | Utility | PG&E Corporation (1) | December 31, 2019 PG&E Corporation Consolidated | Change in Estimated Allowed Claim 2020 (2) | Cash Payment | Reclassified as of June 30, 2020 (3) | Utility | PG&E Corporation (1) | December 31, 2020 PG&E Corporation Consolidated | ||||||||||||||||||||||||||||||||||||||||||||
Financing debt | $ | $ | $ | $ | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
Wildfire-related claims | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||
Trade creditors (4) | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||||||||
Non-qualified benefit plan | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2001 bankruptcy disputed claims | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer deposits & advances | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Other | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Liabilities Subject to Compromise | $ | $ | $ | $ | $ | ( | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2020 | |||||||||||||||||
(in millions) | Utility | PG&E Corporation (1) | PG&E Corporation Consolidated | ||||||||||||||
Debtor-in-possession financing costs | $ | $ | $ | ||||||||||||||
Legal and other (2) | |||||||||||||||||
Interest and other | ( | ( | ( | ||||||||||||||
Total reorganization items, net | $ | $ | $ | ||||||||||||||
Petition Date Through December 31, 2019 | |||||||||||||||||
(in millions) | Utility | PG&E Corporation (1) | PG&E Corporation Consolidated | ||||||||||||||
Debtor-in-possession financing costs | $ | $ | $ | ||||||||||||||
Legal and other | |||||||||||||||||
Interest income | ( | ( | ( | ||||||||||||||
Total reorganization items, net | $ | $ | $ | ||||||||||||||
Year Ended | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Electric | |||||||||||
Revenue from contracts with customers | |||||||||||
Residential | $ | $ | |||||||||
Commercial | |||||||||||
Industrial | |||||||||||
Agricultural | |||||||||||
Public street and highway lighting | |||||||||||
Other (1) | ( | ||||||||||
Total revenue from contracts with customers - electric | |||||||||||
Regulatory balancing accounts (2) | |||||||||||
Total electric operating revenue | $ | $ | |||||||||
Natural gas | |||||||||||
Revenue from contracts with customers | |||||||||||
Residential | $ | $ | |||||||||
Commercial | |||||||||||
Transportation service only | |||||||||||
Other (1) | |||||||||||
Total revenue from contracts with customers - gas | |||||||||||
Regulatory balancing accounts (2) | |||||||||||
Total natural gas operating revenue | |||||||||||
Total operating revenues | $ | $ | |||||||||
Estimated Useful | Balance at December 31, | ||||||||||||||||
(in millions, except estimated useful lives) | Lives (years) | 2020 | 2019 | ||||||||||||||
Electricity generating facilities (1) | $ | $ | |||||||||||||||
Electricity distribution facilities | |||||||||||||||||
Electricity transmission facilities | |||||||||||||||||
Natural gas distribution facilities | |||||||||||||||||
Natural gas transmission and storage facilities | |||||||||||||||||
Construction work in progress | |||||||||||||||||
Other | |||||||||||||||||
Total property, plant, and equipment | |||||||||||||||||
Accumulated depreciation | ( | ( | |||||||||||||||
Net property, plant, and equipment | $ | $ | |||||||||||||||
(in millions) | 2020 | 2019 | |||||||||
ARO liability at beginning of year | $ | $ | |||||||||
Liabilities incurred in the current period | |||||||||||
Revision in estimated cash flows | ( | ||||||||||
Accretion | |||||||||||
Liabilities settled | ( | ( | |||||||||
ARO liability at end of year | $ | $ |
(in millions, net of income tax) | Pension Benefits | Other Benefits | Total | ||||||||||||||
Beginning balance | $ | ( | $ | $ | ( | ||||||||||||
Other comprehensive income before reclassifications: | |||||||||||||||||
Unrecognized net actuarial gain (loss) (net of taxes of $ | ( | ( | |||||||||||||||
Regulatory account transfer (net of taxes of $ | ( | ||||||||||||||||
Amounts reclassified from other comprehensive income: | |||||||||||||||||
Amortization of prior service cost (net of taxes of $ | ( | ||||||||||||||||
Amortization of net actuarial (gain) loss (net of taxes of $ | ( | ( | |||||||||||||||
Regulatory account transfer (net of taxes of $ | |||||||||||||||||
Net current period other comprehensive loss | ( | ( | |||||||||||||||
Ending balance | $ | ( | $ | $ | ( | ||||||||||||
(in millions, net of income tax) | Pension Benefits | Other Benefits | Total | ||||||||||||||
Beginning balance | $ | ( | $ | $ | ( | ||||||||||||
Other comprehensive income before reclassifications: | |||||||||||||||||
Unrecognized net actuarial loss (net of taxes of $ | |||||||||||||||||
Regulatory account transfer (net of taxes of $ | ( | ( | ( | ||||||||||||||
Amounts reclassified from other comprehensive income: | |||||||||||||||||
Amortization of prior service cost (net of taxes of $ | ( | ||||||||||||||||
Amortization of net actuarial loss (net of taxes of $ | ( | ||||||||||||||||
Regulatory account transfer (net of taxes of $ | ( | ( | |||||||||||||||
Net current period other comprehensive loss | ( | ( | |||||||||||||||
Ending balance | $ | ( | $ | $ | ( | ||||||||||||
Year Ended December 31, | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Operating lease fixed cost | $ | $ | |||||||||
Operating lease variable cost | |||||||||||
Total operating lease costs | $ | $ |
(in millions) | December 31, 2020 | ||||
2021 | $ | ||||
2022 | |||||
2023 | |||||
2024 | |||||
2025 | |||||
Thereafter | |||||
Total lease payments | |||||
Less imputed interest | ( | ||||
Total | $ |
Balance at December 31, | Recovery Period | ||||||||||||||||
(in millions) | 2020 | 2019 | |||||||||||||||
Pension benefits (1) | $ | $ | Indefinitely | ||||||||||||||
Environmental compliance costs | |||||||||||||||||
Utility retained generation (2) | |||||||||||||||||
Price risk management | |||||||||||||||||
Unamortized loss, net of gain, on reacquired debt | |||||||||||||||||
Catastrophic event memorandum account (3) | |||||||||||||||||
Wildfire expense memorandum account (4) | |||||||||||||||||
Fire hazard prevention memorandum account (5) | |||||||||||||||||
Fire risk mitigation memorandum account (6) | |||||||||||||||||
Wildfire mitigation plan memorandum account (7) | |||||||||||||||||
Deferred income taxes (8) | |||||||||||||||||
Insurance premium costs (9) | |||||||||||||||||
Wildfire mitigation balancing account (10) | |||||||||||||||||
General rate case memorandum accounts (11) | |||||||||||||||||
Vegetation management balancing account (12) | |||||||||||||||||
COVID-19 pandemic protection memorandum accounts (13) | TBD years | ||||||||||||||||
Other | Various | ||||||||||||||||
Total long-term regulatory assets | $ | $ | |||||||||||||||
Balance at December 31, | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Cost of removal obligations (1) | $ | $ | |||||||||
Recoveries in excess of AROs (2) | |||||||||||
Public purpose programs (3) | |||||||||||
Employee benefit plans (4) | |||||||||||
Other | |||||||||||
Total long-term regulatory liabilities | $ | $ | |||||||||
Receivable Balance at December 31, | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Electric transmission | $ | $ | |||||||||
Gas distribution and transmission | |||||||||||
Energy procurement | |||||||||||
Public purpose programs | |||||||||||
Fire hazard prevention memorandum account | |||||||||||
Fire risk mitigation memorandum account | |||||||||||
Wildfire mitigation plan memorandum account | |||||||||||
Wildfire mitigation balancing account | |||||||||||
General rate case memorandum accounts | |||||||||||
Vegetation management balancing account | |||||||||||
Insurance premium costs | |||||||||||
Other | |||||||||||
Total regulatory balancing accounts receivable | $ | $ |
Payable Balance at December 31, | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Electric distribution | $ | $ | |||||||||
Electric transmission | |||||||||||
Gas distribution and transmission | |||||||||||
Energy procurement | |||||||||||
Public purpose programs | |||||||||||
Other | |||||||||||
Total regulatory balancing accounts payable | $ | $ |
(in millions) | Termination Date | Facility Limit | Borrowings Outstanding | Letters of Credit Outstanding | Facility Availability | ||||||||||||||||||||||||
Utility revolving credit facility | July 2023 | $ | (1) | $ | $ | $ | |||||||||||||||||||||||
Utility term loan credit facility | Various(2) | ||||||||||||||||||||||||||||
Utility receivables securitization program | October 2022 | ||||||||||||||||||||||||||||
PG&E Corporation revolving credit facility | July 2023 | ||||||||||||||||||||||||||||
Total credit facilities | $ | $ | $ | $ | |||||||||||||||||||||||||
Balance at | |||||||||||||||||||||||
(in millions) | Contractual Interest Rates (3) | December 31, 2020 | December 31, 2019 | Treatment under Plan on the Effective Date (1) | |||||||||||||||||||
Pre-Petition Debt (2) | |||||||||||||||||||||||
PG&E Corporation | |||||||||||||||||||||||
Borrowings under Pre-Petition Credit Facility | |||||||||||||||||||||||
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | variable rate (4) | $ | $ | Repaid in cash (14) | |||||||||||||||||||
Other borrowings | |||||||||||||||||||||||
Term Loan - Stated Maturity: 2020 | variable rate (5) | Repaid in cash (14) | |||||||||||||||||||||
Total PG&E Corporation Pre-Petition Long-Term Debt | |||||||||||||||||||||||
Utility | |||||||||||||||||||||||
Senior Notes - Stated Maturity: | |||||||||||||||||||||||
2020 through 2022 | Exchanged (15) | ||||||||||||||||||||||
2023 through 2028 | Reinstated (16) | ||||||||||||||||||||||
2034 through 2040 | Exchanged (17) | ||||||||||||||||||||||
2041 through 2042 | Reinstated (16) | ||||||||||||||||||||||
2043 | Exchanged (17) | ||||||||||||||||||||||
2043 through 2047 | Reinstated (16) | ||||||||||||||||||||||
Total Pre-Petition Senior Notes | |||||||||||||||||||||||
Pollution Control Bonds - Stated Maturity: | |||||||||||||||||||||||
Series 2008 F and 2010 E, due 2026 | Repaid in cash (14) | ||||||||||||||||||||||
Series 2009 A-B, due 2026 | variable rate (6) | Exchanged (18) | |||||||||||||||||||||
Series 1996 C, E, F, 1997 B due 2026 | variable rate (7) | Exchanged (18) | |||||||||||||||||||||
Total Pre-Petition Pollution Control Bonds | |||||||||||||||||||||||
Borrowings under Pre-Petition Credit Facilities | |||||||||||||||||||||||
Utility Revolving Credit Facilities - Stated Maturity: 2022 | variable rate (8) | Exchanged (18) | |||||||||||||||||||||
Other borrowings: | |||||||||||||||||||||||
Term Loan - Stated Maturity: 2019 | variable rate (9) | Exchanged (18) | |||||||||||||||||||||
Total Borrowings under Pre-Petition Credit Facility | |||||||||||||||||||||||
Total Utility Pre-Petition Debt | |||||||||||||||||||||||
Total PG&E Corporation Consolidated Pre-Petition Debt | $ | $ | |||||||||||||||||||||
New Long-Term Debt | |||||||||||||||||||||||
PG&E Corporation | |||||||||||||||||||||||
Term Loan - Stated Maturity: 2025 | variable rate (10) | $ | $ | ||||||||||||||||||||
Senior Secured Notes due 2028 | |||||||||||||||||||||||
Senior Secured Notes due 2030 | |||||||||||||||||||||||
Unamortized discount, net of premium and debt issuance costs | ( | ||||||||||||||||||||||
Total PG&E Corporation New Long-Term Debt | |||||||||||||||||||||||
Utility |
Pre-Petition Senior Notes Reinstated as First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
2023 through 2028 | |||||||||||||||||||||||
2041 through 2042 | |||||||||||||||||||||||
2043 through 2047 | |||||||||||||||||||||||
Unamortized discount, net of premium and debt issuance costs | |||||||||||||||||||||||
Total Utility Reinstated New Long-Term Debt | |||||||||||||||||||||||
Pre-Petition Debt Exchanged for First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
2025 | |||||||||||||||||||||||
2026 | |||||||||||||||||||||||
2028 | |||||||||||||||||||||||
2030 | |||||||||||||||||||||||
2040 | |||||||||||||||||||||||
2050 | |||||||||||||||||||||||
Unamortized discount, net of premium and debt issuance costs | ( | ||||||||||||||||||||||
Total Utility Exchanged New Long-Term Debt | |||||||||||||||||||||||
New First Mortgage Bonds - Stated Maturity: | |||||||||||||||||||||||
2022 | variable rate (11) | ||||||||||||||||||||||
2022 | |||||||||||||||||||||||
2027 | |||||||||||||||||||||||
2031 | |||||||||||||||||||||||
2040 | |||||||||||||||||||||||
2050 | |||||||||||||||||||||||
Unamortized discount, net of premium and debt issuance costs | ( | ||||||||||||||||||||||
Total Utility New First Mortgage Bonds | |||||||||||||||||||||||
Credit Facilities - Stated Maturity: 2022 | |||||||||||||||||||||||
Receivables securitization program | variable rate (12) | ||||||||||||||||||||||
variable rate (13) | |||||||||||||||||||||||
Unamortized discount, net of premium and debt issuance costs | ( | ||||||||||||||||||||||
Total Utility New Long-Term Debt | |||||||||||||||||||||||
Total PG&E Corporation Consolidated New Long-Term Debt | $ | $ | |||||||||||||||||||||
(in millions, | |||||||||||||||||||||||||||||||||||||||||
except interest rates) | 2021 | 2022 | 2023 | 2024 | 2025 | Thereafter | Total | ||||||||||||||||||||||||||||||||||
PG&E Corporation | |||||||||||||||||||||||||||||||||||||||||
Average fixed interest rate | % | % | % | % | % | % | % | ||||||||||||||||||||||||||||||||||
Fixed rate obligations | % | % | % | % | % | $ | $ | ||||||||||||||||||||||||||||||||||
Variable interest rate as of December 31, 2020 | % | % | % | % | % | % | % | ||||||||||||||||||||||||||||||||||
Variable rate obligations | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
Utility | |||||||||||||||||||||||||||||||||||||||||
Average fixed interest rate | % | % | % | % | % | % | % | ||||||||||||||||||||||||||||||||||
Fixed rate obligations | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
Variable interest rate as of December 31, 2020 | % | various (1) | % | % | % | % | various (1) | ||||||||||||||||||||||||||||||||||
Variable rate obligations | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
Total consolidated debt | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Stock Options | $ | $ | $ | ||||||||||||||
Restricted stock units | |||||||||||||||||
Performance shares | |||||||||||||||||
Total compensation expense (pre-tax) | $ | $ | $ | ||||||||||||||
Total compensation expense (after-tax) | $ | $ | $ |
2019 | |||||
Expected stock price volatility | % | ||||
Expected annual dividend payment | % | ||||
Risk-free interest rate | |||||
Expected life (years) |
Number of Stock Options | Weighted Average Grant- Date Fair Value | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value | ||||||||||||||||||||
Outstanding at January 1 | $ | $ | — | ||||||||||||||||||||
Granted (1) | — | ||||||||||||||||||||||
Exercised | — | — | |||||||||||||||||||||
Forfeited or expired | ( | — | |||||||||||||||||||||
Outstanding at December 31 | — | ||||||||||||||||||||||
Vested or expected to vest at December 31 | — | ||||||||||||||||||||||
Exercisable at December 31 | $ | $ | — | ||||||||||||||||||||
Number of Restricted Stock Units | Weighted Average Grant- Date Fair Value | ||||||||||
Nonvested at January 1 | $ | ||||||||||
Granted | |||||||||||
Vested | ( | ||||||||||
Forfeited | ( | ||||||||||
Nonvested at December 31 | $ |
Number of Performance Shares | Weighted Average Grant- Date Fair Value | ||||||||||
Nonvested at January 1 | $ | ||||||||||
Granted | |||||||||||
Vested | ( | ||||||||||
Forfeited (1) | ( | ||||||||||
Nonvested at December 31 | $ | ||||||||||
Year Ended December 31, | |||||||||||||||||
(in millions, except per share amounts) | 2020 | 2019 | 2018 | ||||||||||||||
Loss attributable to common shareholders | $ | ( | $ | ( | $ | ( | |||||||||||
Weighted average common shares outstanding, basic | |||||||||||||||||
Add incremental shares from assumed conversions: | |||||||||||||||||
Employee share-based compensation | |||||||||||||||||
Equity Units | |||||||||||||||||
Weighted average common share outstanding, diluted | |||||||||||||||||
Total Loss per common share, diluted | $ | ( | $ | ( | $ | ( |
PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||||||||
(in millions) | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||
Current: | |||||||||||||||||||||||||||||||||||
Federal | $ | ( | $ | $ | ( | $ | ( | $ | $ | ||||||||||||||||||||||||||
State | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
Deferred: | |||||||||||||||||||||||||||||||||||
Federal | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
State | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
Tax credits | ( | ( | ( | ( | ( | ( | |||||||||||||||||||||||||||||
Income tax provision (benefit) | $ | $ | ( | $ | ( | $ | $ | ( | $ | ( |
PG&E Corporation | Utility | ||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||
(in millions) | 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||
Deferred income tax assets: | |||||||||||||||||||||||
Tax carryforwards | $ | $ | $ | $ | |||||||||||||||||||
Compensation | |||||||||||||||||||||||
Wildfire-related claims (1) | |||||||||||||||||||||||
Operating lease liability | |||||||||||||||||||||||
Other (2) | |||||||||||||||||||||||
Total deferred income tax assets | $ | $ | $ | $ | |||||||||||||||||||
Deferred income tax liabilities: | |||||||||||||||||||||||
Property related basis differences | |||||||||||||||||||||||
Regulatory balancing accounts | |||||||||||||||||||||||
Debt financing costs | |||||||||||||||||||||||
Operating lease right of use asset | |||||||||||||||||||||||
Income tax regulatory asset(3) | |||||||||||||||||||||||
Other (4) | |||||||||||||||||||||||
Total deferred income tax liabilities | $ | $ | $ | $ | |||||||||||||||||||
Total net deferred income tax liabilities | $ | $ | $ | $ | |||||||||||||||||||
PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
Federal statutory income tax rate | % | % | % | % | % | % | |||||||||||||||||||||||||||||
Increase (decrease) in income tax rate resulting from: | |||||||||||||||||||||||||||||||||||
State income tax (net of federal benefit) (1) | ( | ||||||||||||||||||||||||||||||||||
Effect of regulatory treatment of fixed asset differences (2) | ( | ||||||||||||||||||||||||||||||||||
Tax credits | ( | ||||||||||||||||||||||||||||||||||
Bankruptcy and emergence (3) | ( | ||||||||||||||||||||||||||||||||||
Other, net (4) | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
Effective tax rate | ( | % | % | % | % | % | % | ||||||||||||||||||||||||||||
PG&E Corporation | Utility | ||||||||||||||||||||||||||||||||||
(in millions) | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||
Balance at beginning of year | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Reductions for tax position taken during a prior year | ( | ( | ( | ( | ( | ( | |||||||||||||||||||||||||||||
Additions for tax position taken during the current year | |||||||||||||||||||||||||||||||||||
Settlements | |||||||||||||||||||||||||||||||||||
Expiration of statute | |||||||||||||||||||||||||||||||||||
Balance at end of year | $ | $ | $ | $ | $ | $ |
(in millions) | December 31, 2020 | Expiration Year | |||||||||
Federal: | |||||||||||
Net operating loss carryforward - Pre-2018 | $ | 2031 - 2036 | |||||||||
Net operating loss carryforward - Post-2017 | N/A | ||||||||||
Tax credit carryforward | 2029 - 2040 | ||||||||||
State: | |||||||||||
Net operating loss carryforward | $ | 2039 - 2040 | |||||||||
Tax credit carryforward | Various |
Contract Volume | ||||||||||||||||||||
At December 31, | ||||||||||||||||||||
Underlying Product | Instruments | 2020 | 2019 | |||||||||||||||||
Natural Gas (1) (MMBtus (2)) | Forwards, Futures and Swaps | |||||||||||||||||||
Options | ||||||||||||||||||||
Electricity (Megawatt-hours) | Forwards, Futures and Swaps | |||||||||||||||||||
Options | ||||||||||||||||||||
Congestion Revenue Rights (3) | ||||||||||||||||||||
Commodity Risk | |||||||||||||||||||||||
(in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||||||||||
Current assets – other | $ | $ | $ | $ | |||||||||||||||||||
Other noncurrent assets – other | |||||||||||||||||||||||
Current liabilities – other | ( | ( | |||||||||||||||||||||
Noncurrent liabilities – other | ( | ( | |||||||||||||||||||||
Total commodity risk | $ | ( | $ | $ | $ |
Commodity Risk | |||||||||||||||||||||||
(in millions) | Gross Derivative Balance | Netting | Cash Collateral | Total Derivative Balance | |||||||||||||||||||
Current assets – other | $ | $ | ( | $ | $ | ||||||||||||||||||
Other noncurrent assets – other | ( | ||||||||||||||||||||||
Current liabilities – other | ( | ( | |||||||||||||||||||||
Noncurrent liabilities – other | ( | ( | |||||||||||||||||||||
Total commodity risk | $ | $ | $ | $ |
Fair Value Measurements | |||||||||||||||||||||||||||||
At December 31, 2020 | |||||||||||||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | — | $ | |||||||||||||||||||||||
Nuclear decommissioning trusts | |||||||||||||||||||||||||||||
Short-term investments | — | ||||||||||||||||||||||||||||
Global equity securities | — | ||||||||||||||||||||||||||||
Fixed-income securities | — | ||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | |||||||||||||||||||||||||
Total nuclear decommissioning trusts (2) | — | ||||||||||||||||||||||||||||
Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
Electricity | |||||||||||||||||||||||||||||
Gas | |||||||||||||||||||||||||||||
Total price risk management instruments | |||||||||||||||||||||||||||||
Rabbi trusts | |||||||||||||||||||||||||||||
Fixed-income securities | — | ||||||||||||||||||||||||||||
Life insurance contracts | — | ||||||||||||||||||||||||||||
Total rabbi trusts | — | ||||||||||||||||||||||||||||
Long-term disability trust | |||||||||||||||||||||||||||||
Short-term investments | — | ||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | |||||||||||||||||||||||||
Total long-term disability trust | — | ||||||||||||||||||||||||||||
TOTAL ASSETS | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Liabilities: | |||||||||||||||||||||||||||||
Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
Electricity | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
Gas | |||||||||||||||||||||||||||||
TOTAL LIABILITIES | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
Fair Value Measurements | |||||||||||||||||||||||||||||
At December 31, 2019 | |||||||||||||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Netting (1) | Total | ||||||||||||||||||||||||
Assets: | |||||||||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | — | $ | |||||||||||||||||||||||
Nuclear decommissioning trusts | |||||||||||||||||||||||||||||
Short-term investments | — | ||||||||||||||||||||||||||||
Global equity securities | — | ||||||||||||||||||||||||||||
Fixed-income securities | — | ||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | |||||||||||||||||||||||||
Total nuclear decommissioning trusts (2) | — | ||||||||||||||||||||||||||||
Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
Electricity | ( | ||||||||||||||||||||||||||||
Gas | |||||||||||||||||||||||||||||
Total price risk management instruments | ( | ||||||||||||||||||||||||||||
Rabbi trusts | |||||||||||||||||||||||||||||
Fixed-income securities | — | ||||||||||||||||||||||||||||
Life insurance contracts | — | ||||||||||||||||||||||||||||
Total rabbi trusts | — | ||||||||||||||||||||||||||||
Long-term disability trust | |||||||||||||||||||||||||||||
Short-term investments | — | ||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | |||||||||||||||||||||||||
Total long-term disability trust | — | ||||||||||||||||||||||||||||
TOTAL ASSETS | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
Liabilities: | |||||||||||||||||||||||||||||
Price risk management instruments (Note 10) | |||||||||||||||||||||||||||||
Electricity | ( | ||||||||||||||||||||||||||||
Gas | ( | ||||||||||||||||||||||||||||
TOTAL LIABILITIES | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||||||||||
(in millions) | At December 31, 2020 | Valuation Technique | Unobservable Input | |||||||||||||||||||||||||||||
Fair Value Measurement | Assets | Liabilities | Range (1)/Weighted-Average Price (2) | |||||||||||||||||||||||||||||
Congestion revenue rights | $ | $ | Market approach | CRR auction prices | $ ( | |||||||||||||||||||||||||||
Power purchase agreements | $ | $ | Discounted cash flow | Forward prices | $ | |||||||||||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||||||||||
(in millions) | At December 31, 2019 | Valuation Technique | Unobservable Input | |||||||||||||||||||||||||||||
Fair Value Measurement | Assets | Liabilities | Range (1)/Weighted-Average Price (2) | |||||||||||||||||||||||||||||
Congestion revenue rights | $ | $ | Market approach | CRR auction prices | $ ( | |||||||||||||||||||||||||||
Power purchase agreements | $ | $ | Discounted cash flow | Forward prices | $ | |||||||||||||||||||||||||||
Price Risk Management Instruments | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
Asset (liability) balance as of January 1 | $ | $ | |||||||||
Net realized and unrealized gains: | |||||||||||
Included in regulatory assets and liabilities or balancing accounts (1) | ( | ( | |||||||||
Asset (liability) balance as of December 31 | $ | ( | $ | ||||||||
At December 31, | |||||||||||||||||||||||
2020 | 2019 | ||||||||||||||||||||||
(in millions) | Carrying Amount | Level 2 Fair Value | Carrying Amount(1) | Level 2 Fair Value(1)(2) | |||||||||||||||||||
Debt (Note 5) | |||||||||||||||||||||||
PG&E Corporation | $ | $ | $ | $ | |||||||||||||||||||
Utility | |||||||||||||||||||||||
(in millions) | Amortized Cost | Total Unrealized Gains | Total Unrealized Losses | Total Fair Value | |||||||||||||||||||
As of December 31, 2020 | |||||||||||||||||||||||
Nuclear decommissioning trusts | |||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | |||||||||||||||||||
Global equity securities | ( | ||||||||||||||||||||||
Fixed-income securities | ( | ||||||||||||||||||||||
Total (1) | $ | $ | $ | ( | $ | ||||||||||||||||||
As of December 31, 2019 | |||||||||||||||||||||||
Nuclear decommissioning trusts | |||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | |||||||||||||||||||
Global equity securities | ( | ||||||||||||||||||||||
Fixed-income securities | ( | ||||||||||||||||||||||
Total (1) | $ | $ | $ | ( | $ | ||||||||||||||||||
As of | |||||
(in millions) | December 31, 2020 | ||||
Less than 1 year | $ | ||||
1–5 years | |||||
5–10 years | |||||
More than 10 years | |||||
Total maturities of fixed-income securities | $ |
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Proceeds from sales and maturities of nuclear decommissioning investments | $ | $ | $ | ||||||||||||||
Gross realized gains on securities | |||||||||||||||||
Gross realized losses on securities | ( | ( | ( |
(in millions) | 2020 | 2019 | |||||||||
Change in plan assets: | |||||||||||
Fair value of plan assets at beginning of year | $ | $ | |||||||||
Actual return on plan assets | |||||||||||
Company contributions | |||||||||||
Benefits and expenses paid | ( | ( | |||||||||
Fair value of plan assets at end of year | $ | $ | |||||||||
Change in benefit obligation: | |||||||||||
Benefit obligation at beginning of year | $ | $ | |||||||||
Service cost for benefits earned | |||||||||||
Interest cost | |||||||||||
Actuarial loss (1) | |||||||||||
Plan amendments | |||||||||||
Benefits and expenses paid | ( | ( | |||||||||
Benefit obligation at end of year (2) | $ | $ | |||||||||
Funded Status: | |||||||||||
Current liability | $ | ( | $ | ( | |||||||
Noncurrent liability | ( | ( | |||||||||
Net liability at end of year | $ | ( | $ | ( | |||||||
(in millions) | 2020 | 2019 | |||||||||
Change in plan assets: | |||||||||||
Fair value of plan assets at beginning of year | $ | $ | |||||||||
Actual return on plan assets | |||||||||||
Company contributions | |||||||||||
Plan participant contribution | |||||||||||
Benefits and expenses paid | ( | ( | |||||||||
Fair value of plan assets at end of year | $ | $ | |||||||||
Change in benefit obligation: | |||||||||||
Benefit obligation at beginning of year | $ | $ | |||||||||
Service cost for benefits earned | |||||||||||
Interest cost | |||||||||||
Actuarial (gain) loss (1) | ( | ||||||||||
Benefits and expenses paid | ( | ( | |||||||||
Federal subsidy on benefits paid | |||||||||||
Plan participant contributions | |||||||||||
Benefit obligation at end of year | $ | $ | |||||||||
Funded Status: (2) | |||||||||||
Noncurrent asset | $ | $ | |||||||||
Noncurrent liability | ( | ( | |||||||||
Net asset at end of year | $ | $ | |||||||||
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Service cost for benefits earned (1) | $ | $ | $ | ||||||||||||||
Interest cost | |||||||||||||||||
Expected return on plan assets | ( | ( | ( | ||||||||||||||
Amortization of prior service cost | ( | ( | ( | ||||||||||||||
Amortization of net actuarial loss | |||||||||||||||||
Net periodic benefit cost | |||||||||||||||||
Less: transfer to regulatory account (2) | |||||||||||||||||
Total expense recognized | $ | $ | $ | ||||||||||||||
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Service cost for benefits earned (1) | $ | $ | $ | ||||||||||||||
Interest cost | |||||||||||||||||
Expected return on plan assets | ( | ( | ( | ||||||||||||||
Amortization of prior service cost | |||||||||||||||||
Amortization of net actuarial loss | ( | ( | ( | ||||||||||||||
Net periodic benefit cost | $ | ( | $ | $ | |||||||||||||
Pension Plan | PBOP Plans | ||||||||||||||||||||||||||||||||||
December 31, | December 31, | ||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
Discount rate | % | % | % | ||||||||||||||||||||||||||||||||
Rate of future compensation increases | % | % | % | N/A | N/A | N/A | |||||||||||||||||||||||||||||
Expected return on plan assets | % | % | % | ||||||||||||||||||||||||||||||||
Interest crediting rate for cash balance plan | % | % | % | N/A | N/A | N/A |
Pension Plan | PBOP Plans | ||||||||||||||||||||||||||||||||||
2021 | 2020 | 2019 | 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
Global equity securities | % | % | % | % | % | % | |||||||||||||||||||||||||||||
Absolute return | % | % | % | % | % | % | |||||||||||||||||||||||||||||
Real assets | % | % | % | % | % | % | |||||||||||||||||||||||||||||
Fixed-income securities | % | % | % | % | % | % | |||||||||||||||||||||||||||||
Total | % | % | % | % | % | % |
Fair Value Measurements | |||||||||||||||||||||||||||||||||||||||||||||||
At December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
2020 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||
Pension Plan: | |||||||||||||||||||||||||||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
Global equity securities | |||||||||||||||||||||||||||||||||||||||||||||||
Absolute Return | |||||||||||||||||||||||||||||||||||||||||||||||
Real assets | |||||||||||||||||||||||||||||||||||||||||||||||
Fixed-income securities | |||||||||||||||||||||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
PBOP Plans: | |||||||||||||||||||||||||||||||||||||||||||||||
Short-term investments | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
Global equity securities | |||||||||||||||||||||||||||||||||||||||||||||||
Real assets | |||||||||||||||||||||||||||||||||||||||||||||||
Fixed-income securities | |||||||||||||||||||||||||||||||||||||||||||||||
Assets measured at NAV | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
Total | $ | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||
Total plan assets at fair value | $ | $ |
(in millions) | |||||
For the year ended December 31, 2020 | Fixed-Income | ||||
Balance at beginning of year | $ | ||||
Actual return on plan assets: | |||||
Relating to assets still held at the reporting date | |||||
Relating to assets sold during the period | ( | ||||
Purchases, issuances, sales, and settlements: | |||||
Purchases | |||||
Settlements | ( | ||||
Balance at end of year | $ | ||||
(in millions) | |||||
For the year ended December 31, 2019 | Fixed-Income | ||||
Balance at beginning of year | $ | ||||
Actual return on plan assets: | |||||
Relating to assets still held at the reporting date | |||||
Relating to assets sold during the period | |||||
Purchases, issuances, sales, and settlements: | |||||
Purchases | |||||
Settlements | ( | ||||
Balance at end of year | $ |
(in millions) | Pension Plan | PBOP Plans | Federal Subsidy | ||||||||||||||
2021 | ( | ||||||||||||||||
2022 | ( | ||||||||||||||||
2023 | ( | ||||||||||||||||
2024 | ( | ||||||||||||||||
2025 | ( | ||||||||||||||||
Thereafter in the succeeding five years | ( |
Year Ended December 31, | |||||||||||||||||
(in millions) | 2020 | 2019 | 2018 | ||||||||||||||
Utility revenues from: | |||||||||||||||||
Administrative services provided to PG&E Corporation | $ | $ | $ | ||||||||||||||
Utility expenses from: | |||||||||||||||||
Administrative services received from PG&E Corporation | $ | $ | $ | ||||||||||||||
Utility employee benefit due to PG&E Corporation |
Insurance Receivable (in millions) | 2020 Zogg fire | 2019 Kincade fire | 2018 Camp fire | 2017 Northern California wildfires | 2015 Butte fire | Total | |||||||||||||||||||||||||||||
Balance at December 31, 2019 | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
Accrued insurance recoveries | |||||||||||||||||||||||||||||||||||
Reimbursements | ( | ( | ( | ( | |||||||||||||||||||||||||||||||
Balance at December 31, 2020 | $ | $ | $ | $ | $ | $ |
(in millions) | |||||||||||||||||
Description(1) | Expense | Capital | Total | ||||||||||||||
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) | $ | $ | $ | ||||||||||||||
Transmission Safety Inspections and Repairs Expense (TO)(2) | |||||||||||||||||
Vegetation Management Support Costs (FHPMA) | |||||||||||||||||
2017 Northern California Wildfires CEMA Expense and Capital (CEMA) | |||||||||||||||||
2018 Camp Fire CEMA Expense (CEMA) | |||||||||||||||||
2018 Camp Fire CEMA Capital for Restoration (CEMA) | |||||||||||||||||
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) | |||||||||||||||||
Total | $ | $ | $ | ||||||||||||||
Balance at | |||||||||||
(in millions) | December 31, 2020 | December 31, 2019 | |||||||||
Topock natural gas compressor station | $ | $ | |||||||||
Hinkley natural gas compressor station | |||||||||||
Former manufactured gas plant sites owned by the Utility or third parties (1) | |||||||||||
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) | |||||||||||
Fossil fuel-fired generation facilities and sites (3) | |||||||||||
Total environmental remediation liability | $ | $ | |||||||||
Power Purchase Agreements | |||||||||||||||||||||||||||||||||||
(in millions) | Renewable Energy | Conventional Energy | Other | Natural Gas | Nuclear Fuel | Total | |||||||||||||||||||||||||||||
2021 | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||
2022 | |||||||||||||||||||||||||||||||||||
2023 | |||||||||||||||||||||||||||||||||||
2024 | |||||||||||||||||||||||||||||||||||
2025 | |||||||||||||||||||||||||||||||||||
Thereafter | |||||||||||||||||||||||||||||||||||
Total purchase commitments | $ | $ | $ | $ | $ | $ |
(in millions) | Other Commitments | ||||
2021 | $ | ||||
2022 | |||||
2023 | |||||
2024 | |||||
2025 | |||||
Thereafter | |||||
Total minimum lease payments | $ |
(a) | (b) | (c) | |||||||||||||||||||||||||||
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | ||||||||||||||||||||||||||
Equity compensation plans approved by shareholders | 20,902,525 | (2) | $ | 40.07 | (3) | 29,174,205 | (4) | ||||||||||||||||||||||
Equity compensation plans not approved by shareholders | — | — | — | ||||||||||||||||||||||||||
Total equity compensation plans | 20,902,525 | (2) | $ | 40.07 | (3) | 29,174,205 | (4) | ||||||||||||||||||||||
Exhibit Number | Exhibit Description | |||||||
2.1 | ||||||||
3.1 | ||||||||
3.2 | ||||||||
3.3 | ||||||||
3.4 | ||||||||
4.1 | ||||||||
4.2 | ||||||||
4.3 | ||||||||
4.4 | ||||||||
4.5 | ||||||||
4.6 | ||||||||
4.7 | ||||||||
4.8 | ||||||||
4.9 | ||||||||
4.10 | ||||||||
4.11 | ||||||||
4.12 | ||||||||
4.13 | ||||||||
4.14 | ||||||||
4.15 | ||||||||
4.16 | ||||||||
4.17 | ||||||||
4.18 | ||||||||
4.19 | ||||||||
4.20 | ||||||||
4.21 | ||||||||
4.22 | ||||||||
4.23 | ||||||||
4.24 | ||||||||
4.25 | ||||||||
4.26 | ||||||||
4.27 | ||||||||
4.28 | ||||||||
4.29 | ||||||||
4.30 | ||||||||
4.31 | ||||||||
4.32 | ||||||||
4.33 | ||||||||
4.34 | ||||||||
4.35 | ||||||||
4.36 | ||||||||
4.37 | ||||||||
4.38 | ||||||||
4.39 | ||||||||
4.40 | ||||||||
4.41 | ||||||||
4.42 | ||||||||
4.43 | ||||||||
4.44 | ||||||||
4.45 | ||||||||
4.46(a) | ||||||||
4.46(b) | ||||||||
10.1 | ||||||||
10.2 | ||||||||
10.3 | ||||||||
10.4 | ||||||||
10.5 | ||||||||
10.6 | ||||||||
10.7 | ||||||||
10.8 | ||||||||
10.9 | ||||||||
10.10 | ||||||||
10.11 | ||||||||
10.12 | ||||||||
10.13 | ||||||||
10.14 | ||||||||
10.15 | ||||||||
10.16 | ||||||||
10.17 | ||||||||
10.18 | ||||||||
10.19 | ||||||||
10.20 | ||||||||
10.21 | * | |||||||
10.22 | ** | |||||||
10.23 | ** | |||||||
10.24 | ** | |||||||
10.25 | ** | |||||||
10.26 | ** | |||||||
10.27 | ** | |||||||
10.28 | ** | |||||||
10.29 | ** | |||||||
10.30 | ** | |||||||
10.31 | ||||||||
10.32 | ||||||||
10.33 | ||||||||
10.34 | ||||||||
10.35 | ||||||||
10.36 | ||||||||
10.37 | ||||||||
10.38 | ||||||||
10.39 | ||||||||
10.40 | ||||||||
10.41 | ||||||||
10.42 | ||||||||
10.43 | ||||||||
10.44 | ||||||||
10.45 | *** | |||||||
10.46 | *** | |||||||
10.47 | *** | |||||||
10.48 | *** | |||||||
10.49 | *** | |||||||
10.50 | **** | |||||||
10.51 | **** | |||||||
10.52 | **** | |||||||
10.53 | **** | |||||||
10.54 | **** | |||||||
10.55 | ***** | |||||||
10.56 | ***** | |||||||
10.57 | ||||||||
10.58 | ||||||||
10.59 | ||||||||
10.60 | ||||||||
10.61 | ||||||||
10.62 | ||||||||
10.63 | ****** | |||||||
10.64 | ||||||||
10.65 | ||||||||
10.66 | ||||||||
10.67 | ||||||||
10.68 | ||||||||
10.69 | ||||||||
10.70 | ||||||||
10.71 | ||||||||
10.72 | ||||||||
10.73 | ||||||||
10.74 | ||||||||
10.75 | ||||||||
10.76 | ||||||||
10.77 | ||||||||
10.78 | ||||||||
10.79 | ||||||||
10.80 | ||||||||
10.81 | *** | |||||||
10.82 | *** | |||||||
10.83 | *** | |||||||
10.84 | *** | |||||||
10.85 | *** | |||||||
10.86 | *** | |||||||
10.87 | *** | |||||||
10.88 | *** | |||||||
10.89 | *** | |||||||
10.90 | *** | |||||||
10.91 | *** | |||||||
10.92 | *** | |||||||
10.93 | *** | |||||||
10.94 | *** | |||||||
10.95 | *** | |||||||
10.96 | *** | |||||||
10.97 | *** | |||||||
10.98 | *** | |||||||
10.99 | *** | |||||||
10.100 | *** | |||||||
10.101 | *** | |||||||
10.102 | *** | |||||||
10.103 | *** | |||||||
10.104 | *** | |||||||
10.105 | *** | |||||||
10.106 | *** | |||||||
10.107 | *** |
10.108 | *** | |||||||
10.109 | *** | |||||||
10.110 | *** | |||||||
10.111 | *** | |||||||
10.112 | *** | |||||||
10.113 | *** | |||||||
10.114 | *** | |||||||
10.115 | *** | |||||||
10.116 | *** | |||||||
10.117 | *** | |||||||
10.118 | *** | |||||||
10.119 | *** | |||||||
10.120 | *** | |||||||
10.121 | *** | |||||||
10.122 | *** | |||||||
10.123 | *** | |||||||
10.124 | *** | |||||||
10.125 | *** | |||||||
10.126 | *** | |||||||
10.127 | *** | |||||||
10.128 | *** | |||||||
10.129 | *** | |||||||
10.130 | *** | |||||||
10.131 | *** | |||||||
10.132 | *** | |||||||
10.133 | *** | |||||||
21 | ||||||||
23.1 | ||||||||
23.2 | ||||||||
24 | ||||||||
31.1 | ||||||||
31.2 | ******* | |||||||
32.1 | ******* | |||||||
32.2 | ||||||||
101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||
101.SCH | XBRL Taxonomy Extension Schema Document | |||||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |||||||
101.LAB | XBRL Taxonomy Extension Labels Linkbase Document | |||||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |||||||
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |||||||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||
* | This Form of Chapter 11 Plan Backstop Commitment Letter is substantially similar in all material respects to each Chapter 11 Plan Backstop Commitment Letter that is otherwise required to be filed as an exhibit, except as to the Backstop Party and the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Chapter 11 Plan Backstop Commitment Letter). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Chapter 11 Plan Backstop Commitment Letter, with a schedule identifying the Chapter 11 Plan Backstop Commitment Letters omitted and setting forth the material details in which each Chapter 11 Plan Backstop Commitment Letter differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Chapter 11 Plan Backstop Commitment Letter so omitted. | |||||||
** | In accordance with Item 601(a)(5) of Regulation S-K, certain schedules or similar attachments to this exhibit have been omitted from this filing. Such omitted schedules or similar attachments include information about the Subrogation Claims held by each Consenting Subrogation Creditor. The registrant agrees to furnish a supplemental copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request. | |||||||
*** | Management contract or compensatory agreement. | |||||||
**** | The Form of Consent Form is substantially identical in all material respects to each Consent Form that is otherwise required to be filed as an exhibit, except as to the Backstop Party, the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Backstop Commitment Letter) and the amount of such Backstop Party’s Forward Contract Purchase Commitment (as defined in the Consent Form). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Consent Form, with a schedule dated as of June 9, 2020 identifying the Consent Forms omitted and setting forth the material details in which each Consent Form differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted. | |||||||
***** | In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request. | |||||||
****** | The Form of Forward Stock Purchase Agreement is substantially identical in all material respects to each Forward Stock Purchase Agreement that is otherwise required to be filed as an exhibit, except as to the Purchaser (as defined in the Forward Stock Purchase Agreement), the amount of such Purchaser’s Greenshoe Backstop Purchase Amount and the amount of such Purchaser’s Additional Backstop Premium Shares. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the Purchase Agreements omitted and setting forth the material details in which each Forward Stock Purchase Agreement differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted. | |||||||
******* | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report. | |||||||
PG&E CORPORATION | PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||
(Registrant) | (Registrant) | ||||||||||
/s/ PATRICIA K. POPPE | /s/ ADAM L. WRIGHT | ||||||||||
Patricia K. Poppe | Adam L. Wright | ||||||||||
By: | Chief Executive Officer | By: | Executive Vice President, Operations and Chief Operating Officer | ||||||||
Date: | February 25, 2021 | Date: | February 25, 2021 |
Signature | Title | Date | |||||||||||||||
A. Principal Executive Officers | |||||||||||||||||
/s/ PATRICIA K. POPPE | Chief Executive Officer | February 25, 2021 | |||||||||||||||
Patricia K. Poppe | (PG&E Corporation) |
/s/ ADAM L. WRIGHT | Executive Vice President, Operations and Chief Operating Officer | February 25, 2021 | |||||||||||||||
Adam L. Wright | (Pacific Gas and Electric Company) |
/s/ CHRISTOPHER A. FOSTER | Vice President and Interim Chief Financial Officer | February 25, 2021 | |||||||||||||||
Christopher A. Foster | (PG&E Corporation) |
/s/ DAVID S. THOMASON | Vice President, Chief Financial Officer, and | February 25, 2021 | |||||||||||||||
David S. Thomason | Controller (Pacific Gas and Electric Company) |
B. Principal Accounting Officer | |||||||||||||||||
/s/ DAVID S. THOMASON | Vice President, Chief Financial Officer, and | February 25, 2021 | |||||||||||||||
David S. Thomason | Controller (Pacific Gas and Electric Company) |
C. Directors (PG&E Corporation and Pacific Gas and Electric Company, unless otherwise noted) | |||||||||||||||||
* | /s/ RAJAT BAHRI | Director | February 25, 2021 | ||||||||||||||
Rajat Bahri |
* | /s/ CHERYL F. CAMPBELL | Director | February 25, 2021 | ||||||||||||||
Cheryl F. Campbell |
* | /s/ KERRY W. COOPER | Director | February 25, 2021 | ||||||||||||||
Kerry W. Cooper |
* | /s/ JESSICA L. DENECOUR | Director | February 25, 2021 | ||||||||||||||
Jessica L. Denecour |
* | /s/ MARK E. FERGUSON III | Director | February 25, 2021 | ||||||||||||||
Mark E. Ferguson III |
* | /s/ ROBERT C. FLEXON | Director | February 25, 2021 | ||||||||||||||
Robert C. Flexon | Chair of the Board (PG&E Corporation) |
* | /s/ W. CRAIG FUGATE | Director | February 25, 2021 | ||||||||||||||
W. Craig Fugate |
* | /s/ ARNO L. HARRIS | Director | February 25, 2021 | ||||||||||||||
Arno L. Harris |
* | /s/ MICHAEL R. NIGGLI, JR. | Director | February 25, 2021 | ||||||||||||||
Michael R. Niggli, Jr. |
* | /s/ PATRICIA K. POPPE | Director | February 25, 2021 | ||||||||||||||
Patricia K. Poppe |
* | /s/ DEAN L. SEAVERS | Director | February 25, 2021 | ||||||||||||||
Dean L. Seavers | Chair of the Board (Pacific Gas and Electric Company) |
* | /s/ WILLIAM L. SMITH | Director | February 25, 2021 | ||||||||||||||
William L. Smith |
* | /s/ OLUWADARA J. TRESEDER | Director | February 25, 2021 | ||||||||||||||
Oluwadara J. Treseder |
* | /s/ BENJAMIN F. WILSON | Director | February 25, 2021 | ||||||||||||||
Benjamin F. Wilson |
* | /s/ ADAM L. WRIGHT | Director (Pacific Gas and Electric Company) | February 25, 2021 | ||||||||||||||
Adam L. Wright |
* | /s/ JOHN M. WOOLARD | Director | February 25, 2021 | ||||||||||||||
John M. Woolard |
*By: | /s/ JOHN R. SIMON | February 25, 2021 | |||||||||||||||
John R. Simon, Attorney-in-Fact |
Years Ended December 31, | |||||||||||||||||
(in millions, except per share amounts) | 2020 | 2019 | 2018 | ||||||||||||||
Administrative service revenue | $ | $ | $ | ||||||||||||||
Operating expenses | ( | ( | ( | ||||||||||||||
Interest income | |||||||||||||||||
Interest expense | ( | ( | ( | ||||||||||||||
Other income (expense) | ( | ||||||||||||||||
Reorganization items, net | ( | ( | |||||||||||||||
Equity in earnings of subsidiaries | ( | ( | |||||||||||||||
Loss before income taxes | ( | ( | ( | ||||||||||||||
Income tax provision (benefit) | ( | ||||||||||||||||
Net loss | $ | ( | $ | ( | $ | ( | |||||||||||
Other Comprehensive Income (Loss) | |||||||||||||||||
Pension and other postretirement benefit plans obligations (net of taxes of $ | $ | ( | $ | ( | $ | ||||||||||||
Total other comprehensive income (loss) | ( | ( | |||||||||||||||
Comprehensive Loss | $ | ( | $ | ( | $ | ( | |||||||||||
Weighted Average Common Shares Outstanding, Basic | |||||||||||||||||
Weighted Average Common Shares Outstanding, Diluted | |||||||||||||||||
Net loss per common share, basic | $ | ( | $ | ( | $ | ( | |||||||||||
Net loss per common share, diluted | $ | ( | $ | ( | $ | ( |
Balance at December 31, | |||||||||||
(in millions) | 2020 | 2019 | |||||||||
ASSETS | |||||||||||
Current Assets | |||||||||||
Cash and cash equivalents | $ | $ | |||||||||
Advances to affiliates | |||||||||||
Income taxes receivable | |||||||||||
Other current assets | |||||||||||
Total current assets | |||||||||||
Noncurrent Assets | |||||||||||
Equipment | |||||||||||
Accumulated depreciation | ( | ( | |||||||||
Net equipment | |||||||||||
Investments in subsidiaries | |||||||||||
Other investments | |||||||||||
Operating lease right of use asset | |||||||||||
Deferred income taxes | |||||||||||
Total noncurrent assets | |||||||||||
Total Assets | $ | $ | |||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||||
Current Liabilities | |||||||||||
Long-term debt, classified as current | |||||||||||
Accounts payable – other | |||||||||||
Operating lease liabilities | |||||||||||
Other current liabilities | |||||||||||
Total current liabilities | |||||||||||
Noncurrent Liabilities | |||||||||||
Debtor-in-possession financing | |||||||||||
Operating lease liabilities | |||||||||||
Other noncurrent liabilities | |||||||||||
Total noncurrent liabilities | |||||||||||
Liabilities Subject to Compromise | |||||||||||
Common Shareholders’ Equity | |||||||||||
Common stock | |||||||||||
Reinvested earnings | ( | ( | |||||||||
Accumulated other comprehensive income (loss) | ( | ( | |||||||||
Total common shareholders’ equity | |||||||||||
Total Liabilities and Shareholders’ Equity | $ | $ |
Year ended December 31, | |||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||
Cash Flows from Operating Activities: | |||||||||||||||||
Net loss | $ | ( | $ | ( | $ | ( | |||||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
Stock-based compensation amortization | |||||||||||||||||
Equity in earnings of subsidiaries | ( | ||||||||||||||||
Deferred income taxes and tax credits-net | ( | ( | |||||||||||||||
Reorganization items, net (Note 2) | |||||||||||||||||
Current income taxes receivable/payable | |||||||||||||||||
Liabilities subject to compromise | |||||||||||||||||
Other | ( | ||||||||||||||||
Net cash provided by (used in) operating activities | ( | ||||||||||||||||
Cash Flows From Investing Activities: | |||||||||||||||||
Investment in subsidiaries | ( | ( | |||||||||||||||
Net cash used in investing activities | ( | ( | |||||||||||||||
Cash Flows From Financing Activities: | |||||||||||||||||
Debtor-in-possession credit facility debt issuance costs | ( | ||||||||||||||||
Bridge facility financing fees | ( | ||||||||||||||||
Borrowings under revolving credit facility | |||||||||||||||||
Repayments under revolving credit facility | ( | ||||||||||||||||
Net repayments of commercial paper | ( | ||||||||||||||||
Short-term debt financing | |||||||||||||||||
Proceeds from issuance of long-term debt | |||||||||||||||||
Repayment of long-term debt | ( | ( | |||||||||||||||
Common stock issued | |||||||||||||||||
Equity Units issued | |||||||||||||||||
Net cash provided by financing activities | |||||||||||||||||
Net change in cash and cash equivalents | ( | ||||||||||||||||
Cash and cash equivalents at January 1 | |||||||||||||||||
Cash and cash equivalents at December 31 | $ | $ | $ | ||||||||||||||
Supplemental disclosures of cash flow information | |||||||||||||||||
Cash received (paid) for: | |||||||||||||||||
Interest, net of amounts capitalized | $ | ( | $ | ( | $ | ( | |||||||||||
Income taxes, net | |||||||||||||||||
Supplemental disclosures of noncash investing and financing activities | |||||||||||||||||
Operating lease liabilities arising from obtaining ROU assets | $ | $ | $ | ||||||||||||||
Common stock issued in satisfaction of liabilities |
(in millions) | Additions | |||||||||||||||||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions (2) | Balance at End of Period | |||||||||||||||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||||||||||||||
2020: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
2019: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
2018: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ |
(in millions) | Additions | |||||||||||||||||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions (2) | Balance at End of Period | |||||||||||||||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||||||||||||||
2020: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
2019: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
2018: | ||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (1) | $ | $ | $ | $ | $ |
• | a prepaid forward stock purchase contract of PG&E Corporation entitling the holder to receive a number of shares of our Common Stock on August 16, 2023 (subject to postponement in certain limited circumstances, the “purchase contract settlement date”), or earlier if a “fundamental change” occurs prior to the settlement date or if the holder has elected “early settlement” (in each case, as defined herein and described below), determined by reference to the settlement rate described below; and |
• | a U.S. treasury strips component. |
• | deliver the relevant Equity Units to the purchase contract agent; and |
• | deliver a notice to the purchase contract agent requesting that the purchase contract agent instruct the custodian to release to the holder the U.S. treasury strips underlying those Equity Units. |
• | irrevocably authorized and directed the purchase contract agent to execute, deliver and perform on its behalf the purchase contract agreement, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes; |
• | in the case of a purchase contract that is a component of an Equity Unit, or that is evidenced by a separate purchase contract, irrevocably authorized and directed the purchase contract agent to execute, deliver and hold on its behalf the separate purchase contract or the component purchase contract evidencing such purchase contract, and appointed the purchase contract agent as its attorney-in-fact for any and all such purposes; |
• | consented to, and agreed to be bound by, the terms and provisions of the purchase contract agreement; |
• | in the case of a holder of an Equity Unit, agreed, for all purposes, including U.S. federal income tax purposes, to treat: |
• | an Equity Unit as an investment unit composed of two separate instruments, in accordance with its form; |
• | the allocation of the stated amount per Equity Unit between the purchase contract and the U.S. treasury strips component so that such holder’s initial tax basis in each purchase contract will be $82.8574 and such holder’s initial tax basis in each U.S. treasury strips component will be $17.1402; |
• | represented and warranted that neither the beneficial holder of the purchase contracts (including for these purposes a purchase contract that is a component of any Equity Unit) nor, to the knowledge of such beneficial holder, any other person, would become a “Substantial Shareholder” (as defined in the Amended Articles) as a result of such beneficial holder’s acquisition of purchase contracts (treating the beneficial holder and any such other person as actually holding, solely for purposes of this representation, the number of shares of our Common Stock that would be received upon settlement at the maximum settlement rate of all purchase contracts acquired or beneficially owned by such beneficial holder or any such other person, as applicable, but treating all other purchase contracts as still unsettled), and, for the avoidance of doubt, taking into account such beneficial holder’s and any such other person’s (i) current ownership of our Common Stock and any of the Utility’s preferred stock and (ii) other acquisitions of our Common Stock and any of the Utility’s preferred stock (if any) concurrent with or in connection with such beneficial holder’s acquisition of purchase contracts; and |
• | appointed the custodian to hold on its behalf and to receive payments related to the U.S. treasury strips components and agreed to indemnify the custodian from and against any liability it may incur in connection with such appointment in the absence of gross negligence or willful misconduct on its part. |
• | if the applicable market value of our Common Stock is greater than the threshold appreciation price, then the holder will receive 8.5929 shares of Common Stock for each purchase contract (the “minimum settlement rate”); |
• | if the applicable market value of our Common Stock is greater than or equal to the reference price but less than or equal to the threshold appreciation price, then the holder will receive a number of shares of Common Stock for each purchase contract equal to the Equity Unit stated amount of $100, divided by the applicable market value; and |
• | if the applicable market value of our Common Stock is less than the reference price, then the holder will receive 10.5263 shares of Common Stock for each purchase contract (the “maximum settlement rate”). |
Assumed Applicable Market Value | Number of Shares of Common Stock | ||||||||||
$2.00 | 10.5263 | ||||||||||
$4.00 | 10.5263 | ||||||||||
$6.00 | 10.5263 | ||||||||||
$8.00 | 10.5263 | ||||||||||
$9.50 | 10.5263 | ||||||||||
$10.50 | 9.5238 | ||||||||||
$11.64 | 8.5929 | ||||||||||
$13.00 | 8.5929 | ||||||||||
$15.00 | 8.5929 | ||||||||||
$18.00 | 8.5929 | ||||||||||
$21.00 | 8.5929 | ||||||||||
$25.00 | 8.5929 | ||||||||||
$30.00 | 8.5929 | ||||||||||
$35.00 | 8.5929 |
• | any “person” or “group” within the meaning of Section 13(d) of the Exchange Act of 1934, as amended (the “Exchange Act”), other than us, any of our wholly owned subsidiaries and any of our and their employee benefit plans, files a Schedule TO or any other schedule, form or report under the Exchange Act disclosing that such person or group has become the direct or indirect “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the outstanding shares of our Common Stock; | ||||||||||
• | the consummation of (A) any recapitalization, reclassification or change of our Common Stock (other than changes resulting from a subdivision or combination) as a result of which our Common Stock would be converted into, or exchanged for, stock, other securities, other property or assets; (B) any share exchange, consolidation or merger of us pursuant to which our Common Stock will be converted into cash, securities or other property or assets; or (C) any sale, lease or other transfer in one transaction or a series of transactions of all or substantially all of the consolidated assets of us and our subsidiaries, taken as a whole, to any person other than one of our wholly owned subsidiaries; or | ||||||||||
• | our Common Stock (or other Common Stock receivable upon settlement of the holder’s purchase contracts, if applicable) ceases to be listed or quoted on any of the NYSE, the NASDAQ Global Select Market or the NASDAQ Global Market (or any of their respective successors). |
• | in the case of a fundamental change described in the second bullet of the definition of “fundamental change” in which all holders of shares of our Common Stock receive only cash in the fundamental change, the stock price will be the cash amount paid per share of our Common Stock; and |
• | in all other cases, the stock price will be the arithmetic average of the daily VWAPs of our Common Stock over the five consecutive trading day period ending on the trading day immediately preceding such fundamental change effective date. |
Stock Price | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fundamental Change Effective Date | $ | 2.00 | $ | 4.00 | $ | 6.00 | $ | 8.00 | $ | 9.50 | $ | 10.50 | $ | 11.64 | $ | 13.00 | $ | 15.00 | $ | 18.00 | $ | 21.00 | $ | 25.00 | $ | 30.00 | $ | 35.00 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
July 1, 2020 | 10.3248 | 9.9939 | 9.5052 | 9.0924 | 8.8699 | 8.7592 | 8.663 | 8.5811 | 8.5065 | 8.4547 | 8.4379 | 8.4357 | 8.4415 | 8.4475 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
August 16, 2020 | 10.3372 | 10.0252 | 9.5399 | 9.12 | 8.8914 | 8.7774 | 8.6781 | 8.5936 | 8.5167 | 8.4633 | 8.4459 | 8.4433 | 8.4487 | 8.4542 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
February 16, 2021 | 10.3813 | 10.1499 | 9.6883 | 9.2397 | 8.9836 | 8.8538 | 8.7404 | 8.6438 | 8.5564 | 8.4966 | 8.4769 | 8.4729 | 8.4765 | 8.4803 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
August 16, 2021 | 10.417 | 10.2681 | 9.852 | 9.3763 | 9.0862 | 8.9361 | 8.8043 | 8.6924 | 8.5927 | 8.5265 | 8.5055 | 8.5005 | 8.5025 | 8.5047 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
February 16, 2022 | 10.4472 | 10.3753 | 10.0399 | 9.5445 | 9.2088 | 9.0297 | 8.8715 | 8.7386 | 8.6236 | 8.5521 | 8.5314 | 8.5265 | 8.5273 | 8.5282 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
August 16, 2022 | 10.4738 | 10.4551 | 10.2454 | 9.7595 | 9.3615 | 9.137 | 8.9374 | 8.7734 | 8.6408 | 8.5695 | 8.553 | 8.5498 | 8.5498 | 8.55 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
February 16, 2023 | 10.5002 | 10.4998 | 10.4479 | 10.0823 | 9.5949 | 9.276 | 8.9882 | 8.7694 | 8.6265 | 8.5775 | 8.5721 | 8.5716 | 8.5716 | 8.5716 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
August 16, 2023 | 10.5263 | 10.5263 | 10.5263 | 10.5263 | 10.5263 | 9.5238 | 8.5929 | 8.5929 | 8.5929 | 8.5929 | 8.5929 | 8.5929 | 8.5929 | 8.5929 |
• | if the applicable stock price is between two stock prices in the table or the applicable fundamental change effective date is between two fundamental change effective dates in the table, the fundamental change early settlement rate will be determined by straight line interpolation between the fundamental change early settlement rates set forth for the higher and lower stock prices and the earlier and later fundamental change effective dates, as applicable, based on a 365- or 366-day year, as applicable; |
• | if the applicable stock price is greater than $35.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above), then the fundamental change early settlement rate will be the minimum settlement rate; or |
• | if the applicable stock price is less than $2.00 per share (subject to adjustment in the same manner and at the same time as the stock prices set forth in the column headings of the table above, the “minimum stock price”), the fundamental change early settlement rate will be determined as if the stock price equaled the minimum stock price, and using straight line interpolation, as described in the first bullet of this paragraph, if the fundamental change effective date is between two fundamental change effective dates in the table. |
(1) | If we exclusively issue shares of our Common Stock as a dividend or distribution on shares of our Common Stock, or if we effect a share split or share combination, each fixed settlement rate will be adjusted based on the following formula: |
CR1 = CR0 x | OS1 | |||||||||||||
OS0 |
CR0 | = | such fixed settlement rate in effect immediately prior to the close of business on the record date (as defined below) of such dividend or distribution, or immediately prior to the open of business on the effective date of such share split or share combination, as applicable; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the close of business on such record date or immediately after the open of business on such effective date, as applicable; | ||||||||||||
OS0 | = | the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date or immediately prior to the open of business on such effective date, as applicable, before giving effect to such dividend, distribution, share split or share combination; and | ||||||||||||
OS1 | = | the number of shares of our Common Stock outstanding immediately after giving effect to such dividend, distribution, share split or share combination. |
(2) | If we issue to all or substantially all holders of our Common Stock any rights, options or warrants entitling them, for a period of not more than 45 calendar days after the announcement date of such issuance, to subscribe for or purchase shares of our Common Stock at a price per share that is less than the average VWAP per share of our Common Stock for the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of such issuance, each fixed settlement rate will be increased based on the following formula: |
CR1 = CR0 x | OS0 + X | |||||||||||||
OS0 + Y |
CR0 | = | such fixed settlement rate in effect immediately prior to the close of business on the record date for such issuance; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the close of business on such record date; | ||||||||||||
OS0 | = | the number of shares of our Common Stock outstanding immediately prior to the close of business on such record date; | ||||||||||||
X | = | the total number of shares of our Common Stock issuable pursuant to such rights, options or warrants; and | ||||||||||||
Y | = | the number of shares of our Common Stock equal to (i) the aggregate price payable to exercise such rights, options or warrants, divided by (ii) the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the date of announcement of the issuance of such rights, options or warrants. |
(3) | If we distribute shares of our capital stock, evidences of our indebtedness, other assets or property of ours or rights, options or warrants to acquire our capital stock or other securities, to all or substantially all holders of our Common Stock, excluding: |
• | dividends, distributions or issuances as to which the provisions set forth in clause (1) or (2) shall apply; |
• | dividends or distributions paid exclusively in cash as to which the provisions set forth in clause (4) below shall apply; |
• | any distributions upon conversion of, or in exchange for, our Common Stock in connection with a recapitalization, reclassification, change, consolidation, merger or other combination, share exchange, or sale, lease or other transfer or disposition resulting in the change in the consideration due upon settlement of the purchase contracts as described below under “—Recapitalizations, Reclassifications and Changes of Our Common Stock”; | ||||||||||
• | except as otherwise described below, rights issued pursuant to a shareholder rights plan adopted by us; and | ||||||||||
• | spin-offs as to which the provisions set forth below in this clause (3) shall apply; |
CR1 = CR0 x | SP0 | |||||||||||||
SP0 - FMV |
CR0 | = | such fixed settlement rate in effect immediately prior to the close of business on the record date for such distribution; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the close of business on such record date; | ||||||||||||
SP0 | = | the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the trading day immediately preceding the ex-date (as defined below) for such distribution; and | ||||||||||||
FMV | = | the fair market value (as determined by our board of directors in good faith) of the shares of capital stock, evidences of indebtedness, assets, property, rights, options or warrants so distributed, expressed as an amount per share of our Common Stock on the ex-date for such distribution. |
• | we will not adjust the fixed settlement rates pursuant to the foregoing in this clause (3) until the earliest of these triggering events occurs; and | ||||||||||
• | we will readjust the fixed settlement rates to the extent any of these rights, options or warrants are not exercised before they expire; provided that the rights, options or warrants trade together with our Common Stock and will be issued in respect of future issuances of the shares of our Common Stock. |
CR1 = CR0 x | FMV0 + MP0 | |||||||||||||
MP0 |
CR0 | = | such fixed settlement rate in effect immediately prior to the open of business on the ex-date for the spin-off; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the open of business on the ex-date for the spin-off; | ||||||||||||
FMV0 | = | the average VWAP per share of the capital stock or similar equity interest distributed to holders of our Common Stock applicable to one share of our Common Stock over the ten consecutive trading day period commencing on, and including, the ex-date for the spin-off, or the “valuation period”; and | ||||||||||||
MP0 | = | the average VWAP per share of our Common Stock over the valuation period. |
(4) | If any cash dividend or distribution is made to all or substantially all holders of our Common Stock, each fixed settlement rate will be adjusted based on the following formula: |
CR1 = CR0 x | SP0 | |||||||||||||
SP0 - C |
CR0 | = | such fixed settlement rate in effect immediately prior to the close of business on the record date for such dividend or distribution; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the close of business on the record date for such dividend or distribution; | ||||||||||||
SP0 | = | the average VWAP per share of our Common Stock over the ten consecutive trading day period ending on, and including, the Trading Day immediately preceding the ex-date for such distribution; and | ||||||||||||
C | = | the amount in cash per share we distribute to all or substantially all holders of our Common Stock. |
(5) | If we or any of our subsidiaries make a payment in respect of a tender or exchange offer for our Common Stock, to the extent that the cash and value of any other consideration included in the payment per share of Common Stock exceeds the average VWAP per share of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender or exchange offer, or the “expiration date”, each fixed settlement rate will be increased based on the following formula: |
CR1 = CR0 x | AC + (SP1x OS1) | |||||||||||||
OS0 x SP1 |
CR0 | = | such fixed settlement rate in effect immediately prior to the close of business on the expiration date; | ||||||||||||
CR1 | = | such fixed settlement rate in effect immediately after the close of business on the expiration date; | ||||||||||||
AC | = | the aggregate value of all cash and any other consideration (as determined by our board of directors in good faith) paid or payable for shares purchased in such tender or exchange offer; | ||||||||||||
OS0 | = | the number of shares of our Common Stock outstanding immediately prior to the expiration date (prior to giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer); | ||||||||||||
OS1 | = | the number of shares of our Common Stock outstanding immediately after the expiration date (after giving effect to the purchase of all shares accepted for purchase or exchange in such tender or exchange offer); and | ||||||||||||
SP1 | = | the average VWAP of our Common Stock over the ten consecutive trading day period commencing on, and including, the trading day next succeeding the expiration date (the “averaging period”). |
• | upon the issuance of any shares of our Common Stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in Common Stock under any plan; |
• | upon the issuance of any shares of our Common Stock or options, rights or warrants to purchase those shares pursuant to any present or future benefit or other incentive plan or program of or assumed by us or any of our subsidiaries; |
• | subject to the second immediately preceding paragraph, upon the issuance of any shares of our Common Stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security not described in the preceding bullet and outstanding as of the date the purchase contracts were first issued; |
• | for a change in the par value of our Common Stock; |
• | for stock repurchases that are not tender or exchange offers referred to in clause (5) of the adjustments above, including structured or derivative transactions or pursuant to a stock repurchase program approved by our board of directors that is not a tender or exchange offer referred to in clause (5). |
• | the record date for a dividend or distribution on shares of our Common Stock occurs after the end of the 20 consecutive trading day period used for calculating the applicable market value and before the purchase contract settlement date; and |
• | that dividend or distribution would have resulted in an adjustment of the number of shares issuable to the holders of the purchase contracts had such record date occurred on or before the last trading day of such 20-trading day period, |
• | any consolidation or merger of us with or into another person; |
• | any sale, transfer, lease or conveyance to another person of all or substantially all of our property and assets; |
• | any reclassification of our Common Stock into securities (other than a share split or share combination), including securities other than our Common Stock; or |
• | any statutory exchange of our securities with another person (other than in connection with a consolidation or merger), |
• | to evidence the succession of another person to us, and the assumption by any such successor of the covenants and obligations of ours in the purchase contract agreement and the units and separate purchase contracts, if any; |
• | to add to the covenants for the benefit of holders of purchase contracts or to surrender any of our rights or powers under the agreement; |
• | to evidence and provide for the acceptance of appointment of a successor purchase contract agent; |
• | upon the occurrence of a reorganization event, solely (i) to provide that each purchase contract will become a contract to purchase exchange property and (ii) to effect the related changes to the terms of the purchase contracts, in each case, as required by the applicable provisions of the purchase contract agreement; |
• | to conform the provisions of the purchase contract agreement to the “Description of the Purchase Contracts” and “Description of the Equity Units” sections in the preliminary prospectus supplement which forms a part of the registration statement on which the Equity Units are registered, as supplemented by the related pricing term sheet; |
• | to cure any ambiguity or manifest error, to correct or supplement any provisions that may be inconsistent or defective; and | ||||||||||
• | to make any other provisions with respect to such matters or questions, so long as such action does not adversely affect the interest of the holders in any material respect. |
• | reduce the number of shares of Common Stock deliverable upon settlement of the purchase contract (except to the extent expressly required pursuant to the anti-dilution adjustments); |
• | change the purchase contract settlement date, or adversely modify the early settlement right or the fundamental change early settlement right; or |
• | reduce the above-stated percentage of outstanding purchase contracts the consent of the holders of which is required for the modification or amendment of the provisions of the purchase contracts or the purchase contract agreement. |
• | the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall expressly assume all of our obligations under the purchase contracts and the purchase contract agreement; |
• | the successor entity to such consolidation or merger, or the entity which acquires all or substantially all of our assets, shall be a corporation organized and existing under the laws of the United States or any state thereof or the District of Columbia; and |
• | immediately after the merger, consolidation, sale, assignment, transfer, lease or conveyance, no default has occurred and is continuing under the purchase contracts or the purchase contract agreement. |
Maturity | Face Amount | CUSIP | ||||||||||||||||||||||||
August 15, 2020 | $ | 33,000 | 912803AU7 | |||||||||||||||||||||||
November 15, 2020 | $ | 66,000 | 912820WZ6 | |||||||||||||||||||||||
February 15, 2021 | $ | 66,000 | 912803AV5 | |||||||||||||||||||||||
May 15, 2021 | $ | 66,000 | 912803AW3 | |||||||||||||||||||||||
August 15, 2021 | $ | 66,000 | 912821AG0 | |||||||||||||||||||||||
November 15, 2021 | $ | 66,000 | 912820ZH3 | |||||||||||||||||||||||
February 15, 2022 | $ | 66,000 | 912833LG3 | |||||||||||||||||||||||
May 15, 2022 | $ | 66,000 | 912821BZ7 | |||||||||||||||||||||||
August 15, 2022 | $ | 66,000 | 912820RU3 | |||||||||||||||||||||||
November 15, 2022 | $ | 66,000 | 912820SH1 | |||||||||||||||||||||||
February 15, 2023 | $ | 66,000 | 912820B30 | |||||||||||||||||||||||
May 15, 2023 | $ | 66,000 | 912820F36 | |||||||||||||||||||||||
August 15, 2023 | $ | 66,000 | 912820G84 |
• | the depositary has notified the purchase contract agent that it is unwilling or unable to continue as depositary for such global Equity Unit certificates or global purchase contract certificates, as the case may be, or has ceased to be qualified to act as such as required by the purchase contract agreement; |
• | there shall have occurred and be continuing a default by us in respect of our obligations under the purchase contract agreement; or |
• | the beneficial holder of Equity Units elects to withdraw the U.S. treasury strips evidenced by one or more of its Equity Units and elects to hold the purchase contracts in definitive form. |
• | are not be entitled to have the global purchase contract certificates or the purchase contracts represented thereby registered in their respective names; | ||||||||||
• | will not receive or be entitled to receive physical delivery of Equity Unit certificates or purchase contract certificates, as the case may be, in exchange therefor; and |
• | are not be considered to be owners or holders of global Equity Unit certificates or any Equity Units represented thereby or global purchase contract certificates or any purchase contracts represented thereby, for any purpose under the Equity Units, the purchase contracts or the purchase contract agreement. |
PG&E AR FACILITY, LLC, | ||||||||||||||
as Buyer | ||||||||||||||
By: | /s/ MARGARET BECKER | |||||||||||||
Name: | Margaret Becker | |||||||||||||
Title: | Vice President and Treasurer |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||
as the Servicer and as the Originator | ||||||||||||||
By: | /s/ DAVID S. THOMASON | |||||||||||||
Name: | David S. Thomason | |||||||||||||
Title: | Vice President, Chief Financial Officer and Controller |
MUFG BANK, LTD., | ||||||||||||||
as Administrative Agent | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as Group Agent for the MUFG Group | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
VICTORY RECEIVABLES CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ KEVIN J. CORRIGAN | |||||||||||||
Name: | Kevin J. Corrigan | |||||||||||||
Title: | Vice President |
MIZUHO BANK, LTD., | ||||||||||||||
as Group Agent for the Mizuho Group | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
MIZUHO BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
BNP PARIBAS, | ||||||||||||||
as a Group Agent for the BNP Group | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
BNP PARIBAS, | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
STARBIRD FUNDING CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ DAVID V. DEANGELIS | |||||||||||||
Name: | David V. DeAngelis | |||||||||||||
Title: | Vice President |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as Group Agent for the JPM Group | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
JUPITER SECURITIZATION COMPANY LLC, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
PG&E AR FACILITY, LLC, | ||||||||||||||
By: | /s/ MARGARET BECKER | |||||||||||||
Name: | Margaret Becker | |||||||||||||
Title: | Vice President and Treasurer |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||
as Holder | ||||||||||||||
By: | /s/ DAVID S. THOMASON | |||||||||||||
Name: | David S. Thomason | |||||||||||||
Title: | Vice President, Chief Financial Officer and Controller |
MUFG BANK, LTD., | ||||||||||||||
as Administrative Agent | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as Group Agent for the MUFG Group | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
VICTORY RECEIVABLES CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ KEVIN J. CORRIGAN | |||||||||||||
Name: | Kevin J. Corrigan | |||||||||||||
Title: | Vice President |
MIZUHO BANK, LTD., | ||||||||||||||
as Group Agent for the Mizuho Group | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
MIZUHO BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
BNP PARIBAS, | ||||||||||||||
as a Group Agent for the BNP Group | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
BNP PARIBAS, | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
STARBIRD FUNDING CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ DAVID V. DEANGELIS | |||||||||||||
Name: | David V. DeAngelis | |||||||||||||
Title: | Vice President |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as Group Agent for the JPM Group | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
JUPITER SECURITIZATION COMPANY LLC, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ MARQUIS GILMORE | |||||||||||||
Name: | Marquis Gilmore | |||||||||||||
Title: | Managing Director |
PG&E AR FACILITY, LLC, | ||||||||||||||
By: | /s/ MARGARET BECKER | |||||||||||||
Name: | Margaret Becker | |||||||||||||
Title: | Vice President and Treasurer |
PACIFIC GAS AND ELECTRIC COMPANY | ||||||||||||||
as the Servicer and as Retention Holder | ||||||||||||||
By: | /s/ DAVID S. THOMASON | |||||||||||||
Name: | David S. Thomason | |||||||||||||
Title: | Vice President, Chief Financial Officer and Controller |
MUFG BANK, LTD., | ||||||||||||||
as Administrative Agent | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as Group Agent for the MUFG Group | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
MUFG BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ERIC WILLIAMS | |||||||||||||
Name: | Eric Williams | |||||||||||||
Title: | Managing Director |
VICTORY RECEIVABLES CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ KEVIN J. CORRIGAN | |||||||||||||
Name: | Kevin J. Corrigan | |||||||||||||
Title: | Vice President |
MIZUHO BANK, LTD., | ||||||||||||||
as Group Agent for the Mizuho Group | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
MIZUHO BANK, LTD., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ RICHARD A. BURKE | |||||||||||||
Name: | Richard A. Burke | |||||||||||||
Title: | Managing Director |
BNP PARIBAS, | ||||||||||||||
as a Group Agent for the BNP Group | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
BNP PARIBAS, | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ ADVAIT JOSHI | |||||||||||||
Name: | Advait Joshi | |||||||||||||
Title: | Director | |||||||||||||
By: | /s/ CHRIS FUKUOKA | |||||||||||||
Name: | Chris Fukuoka | |||||||||||||
Title: | Vice President |
STARBIRD FUNDING CORPORATION, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ DAVID V. DEANGELIS | |||||||||||||
Name: | David V. DeAngelis | |||||||||||||
Title: | Vice President |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as Group Agent for the JPM Group | ||||||||||||||
By: | /s/ CORINA MILLS | |||||||||||||
Name: | Corina Mills | |||||||||||||
Title: | Executive Director |
JPMORGAN CHASE BANK, N.A., | ||||||||||||||
as a Committed Lender | ||||||||||||||
By: | /s/ CORINA MILLS | |||||||||||||
Name: | Corina Mills | |||||||||||||
Title: | Executive Director |
JUPITER SECURITIZATION COMPANY LLC, | ||||||||||||||
as a Conduit Lender | ||||||||||||||
By: | /s/ CORINA MILLS | |||||||||||||
Name: | Corina Mills | |||||||||||||
Title: | Executive Director |
Article 1 DEFINITIONS AND Interpretation | |||||
1.1. Definitions | |||||
1.2. Terms Defined Elsewhere in this Agreement | |||||
1.3. Construction | |||||
Article 2 EXCLUSIVE LICENSE; Closing | |||||
2.1. Exclusive License | |||||
2.2. Purchase Price | |||||
2.3. Purchase Price Adjustment | |||||
2.4. Closing | |||||
2.5. Closing Obligations | |||||
2.6. Certain Payments | |||||
2.7. ANOI Adjustment | |||||
2.8. Tax Treatment | |||||
2.9. Treatment of Certain Cell Sites | |||||
Article 3 REPRESENTATIONS AND WARRANTIES OF Utility | |||||
3.1. Organization and Good Standing | |||||
3.2. Authority and Enforceability | |||||
3.3. No Conflict | |||||
3.4. Cell Sites and Towers | |||||
3.5. Compliance with Law | |||||
3.6. Environmental Compliance | |||||
3.7. Contracts | |||||
3.8. Proceedings; Orders | |||||
3.9. Taxes and Assessments | |||||
3.10. Brokers or Finders | |||||
3.11. Accurate Documents | |||||
3.12. Accuracy of Representations and Warranties | |||||
Article 4 REPRESENTATIONS AND WARRANTIES OF PURCHASER | |||||
4.1. Organization and Good Standing | |||||
4.2. Authority and Enforceability |
4.3. No Conflict | |||||
4.4. Brokers or Finders | |||||
4.6. Proceedings; Orders | |||||
4.7. Solvency | |||||
4.8. Financial Capability | |||||
Article 5 COVENANTS AND AGREEMENTS | |||||
5.1. Access to Books and Records | |||||
5.2. Efforts to Close; Cooperation | |||||
5.3. Confidentiality | |||||
5.4. Public Disclosures | |||||
5.5. Exclusivity | |||||
5.6. Further Assurances | |||||
Article 6 CONDITIONS TO CLOSING | |||||
6.1. Conditions to Obligations of Utility and Purchaser | |||||
6.2. Conditions to Obligations of Purchaser | |||||
6.3. Conditions to Obligations of Utility | |||||
Article 7 INDEMNIFICATION | |||||
7.1. Survival | |||||
7.2. Indemnification by Utility | |||||
7.3. Indemnification by Purchaser | |||||
7.4. Indemnification Procedure for Third Party Claims | |||||
7.5. Direct Claims | |||||
7.6. Failure to Give Timely Notice | |||||
7.7. Subrogation | |||||
7.8. Certain Limitations on Indemnification | |||||
7.9. Indemnification Time Limitations | |||||
7.10. Reduction of Claim | |||||
7.11. Determination of Breach | |||||
7.12. Exclusive Remedy | |||||
Article 8 TERMINATION | |||||
8.1. Termination | |||||
8.2. Effect of Termination | |||||
Article 9 GENERAL PROVISIONS | |||||
9.1. Notices | |||||
9.2. Counterparts | |||||
9.3. Governing Law; Submission to Jurisdiction; Selection of Forum | |||||
9.4. Dispute Resolution | |||||
9.5. Entire Agreement | |||||
9.6. Fees and Expenses |
9.7. Assignment; Successors and Assigns; Third Party Beneficiaries | |||||
9.8. Amendment; Waivers; Etc. | |||||
9.9. Time of Essence | |||||
9.10. Specific Performance | |||||
9.11. Severability | |||||
9.12. Schedules | |||||
9.14. Interpretation |
Table of Contents | |||||
Getting Started | |||||
Your Relocation Handbook | |||||
Important Notices | |||||
Altair Will Administer Your Relocation | |||||
Relocation Summary | |||||
Eligibility for Benefits | |||||
Dependents Eligible for Benefits | |||||
Relocation Repayment Agreement | |||||
Miscellaneous Expense Allowance | |||||
Lease Cancellation | |||||
Relocation Clause | |||||
Home Sale Assistance Program | |||||
You Must Work with Altair | |||||
Eligibility of the Home | |||||
If your home is ineligible for the Home Sale Assistance Program | |||||
If your home is eligible for the Home Sale Assistance Program | |||||
Step-by-Step Guide to Home Sale Assistance Program | |||||
Step 1: Speak with your RMC consultant before signing any agreement(s) with real estate professionals regarding the sale of your home. | |||||
Step 2: Broker’s Market Analysis | |||||
Step 3: Selecting a broker or agent to sell your home | |||||
Step 4: Listing your home for sale | |||||
Step 5: Work closely with the broker and the RMC to locate a buyer for your home. | |||||
Step 6: Review any purchase offers on the home with your RMC consultant. | |||||
Step 7: Amended Value Sale | |||||
Step 8: Closing an Amended Value Sale | |||||
Step 9: Cost of Ownership | |||||
Step 10: Vacating the Home | |||||
Tax Liability | |||||
Guaranteed Purchase Offer | |||||
Required Marketing Period | |||||
Relocation Appraisals determine the value of the Guaranteed Purchase Offer. | |||||
Accepting the Guaranteed Purchase Offer | |||||
Amended Value Sale | |||||
Home Sale Incentive | |||||
Possession Period | |||||
Proration Date | |||||
Pass-back of Gain or Loss on Sale to Employee | |||||
Tax Liability | |||||
Equity Advance |
Tax Liability | |||||
New Home Finding Assistance | |||||
Rental Assistance | |||||
Home Search Trip | |||||
Business Expenses | |||||
Tax Liability | |||||
Lender Referral | |||||
Home Purchase Closing Costs | |||||
Closing Procedures | |||||
Eligible Closing Expenses | |||||
Non-eligible Closing Expenses | |||||
Tax Liability | |||||
Household Goods Moving | |||||
Insurance | |||||
Moving Services | |||||
Household Goods Storage | |||||
Transportation of Automobiles | |||||
Disconnecting and Connecting Appliances/Utilities | |||||
Special or Extraordinary Shipping Requirements Are Your Responsibility | |||||
Authorized Household Goods Eligible for Moving Benefit | |||||
Items NOT Authorized | |||||
Additional Exclusions | |||||
Important Information Concerning Household Goods Shipping | |||||
Tax Liability | |||||
Temporary Living Expenses | |||||
Trips Home | |||||
Tax Liability | |||||
Final Trip | |||||
Tax Liability | |||||
Expense Reporting | |||||
Tax Liability on Relocation Expenses Paid to You or On Your Behalf |
Getting Started |
Altair Will Administer Your Relocation |
Relocation Summary |
PROVISION | OFFICER RELOCATION BENEFITS | ||||
Miscellaneous Expense Allowance | $7,000 (less applicable taxes). | ||||
Lease Cancellation | Necessary cancellation expenses up to two months’ rent. | ||||
Home Sale Assistance | Includes professional home marketing assistance to support efforts to sell your home and implementation of a home sale assistance process that provides significant tax savings for both you and PG&E when an offer is received from an outside buyer. You must call your RMC consultant before contacting a broker to list your home. | ||||
Guaranteed Purchase Offer (GPO) | The RMC prepares an offer for your home based on the average of two objective appraisals. The GPO may be accepted after your home has been marketed for 60 days. | ||||
Equity Advance | Equity advance up to 90% of equity based on the GPO. | ||||
New Home Finding Assistance | Maximum of two trips for a combined total of up to 8 days/7 nights for you and your spouse/registered domestic partner; eligible relocating children may go on one trip. Transportation (baggage fees not covered), lodging and meals (up to $75 per day per adults and children aged 16 and older, and $40 per day per child). Full day rental tour if seeking permanent rental accommodations. | ||||
Lender Referral | The RMC provides counseling and referral to lenders that offer special programs. | ||||
Home Purchase Closing Costs | Reimbursement will be equal to actual costs or 2.0% of the new home purchase price, whichever is less. You must call your RMC consultant before contacting a real estate agent to be eligible for closing cost reimbursement. | ||||
Household Goods Moving | Packing, loading, transportation, and insurance; 90 days in-transit storage for authorized household goods; up to 2 cars shipped if move is over 400 miles and the car shipment is within the U.S. | ||||
Temporary Living Expenses | Up to 6 months of corporate housing; a maximum of 2 round trips or mileage reimbursement for you to return to the departure location OR your spouse/registered domestic partner to visit the destination location. Up to 14 days of rental car while your personal auto is in transit. | ||||
Final Trip | Reasonable expenses for employee and eligible dependents. Meals (up to $75 per day per adult and children aged 16 and older and $40 per day per child) and lodging reimbursed with original receipts. One-way airfare and baggage fees for up to $100 in total per person if move is over 400 miles; or mileage reimbursed at the current IRS rate. One night’s lodging and meals prior to departure, en route, and one night’s expenses at destination. | ||||
Expense Reporting | Employee-paid eligible relocation expenses reimbursed by the RMC upon receiving completed expense form with itemized receipts for all expenses. |
Tax Liability | Most taxable reimbursements are grossed up to compensate for the tax impact on the employee. Gross-up is provided as a financial benefit, but it is not intended to compensate you completely for all tax liabilities. |
Eligibility for Benefits |
Relocation Repayment Agreement |
Miscellaneous Expense Allowance |
Lease Cancellation |
Home Sale Assistance Program |
PG&E Will Pay (if normally required of seller) | PG&E Will Not Pay | ||||
•Document preparation fees •Survey fees •Mortgage release fees •Recording fees •Transfer taxes •Title insurance •Closing and legal fees •Escrow fees •FHA/VA fees (required by seller) •Attorney fees, if an attorney is required to handle the actual closing •Termite or pest inspection •Radon inspection or warranty, if necessary •Normal and reasonable real estate broker’s commission (not to exceed 6% of purchase price, unless approved in advance by PG&E) | •Discount points (FHA, VA or conventional) •Escrow •Insurance •Utility bills •Property taxes •Rent •Seller concessions included in the contract with the buyer, including buyer’s closing costs, home warranties, repairs, remodeling, restoration or renovation of any kind •Expenses to remedy and bring to acceptable standards hazardous conditions in the home, such as: •Radon gas •Friable asbestos •Lead-based paint •Urea formaldehyde foam insulation •Underground storage tanks containing toxic materials •Similar environmental hazards •Pest control |
Guide for Calculation of Equity | |||||
To determine the total “net” cash value of any transaction on the home under the Home Sale Assistance Program, first add together: | 1. The purchase price appearing in the RMC’s contract of sale, wherein you are the seller and the RMC is the purchaser. 2. Any amounts you have prepaid for which you are entitled to receive a prorated refund, such as interest and taxes, but excluding home casualty insurance. | ||||
Then subtract from the above the total of the following amounts (if any) that are applicable: | 1. All outstanding indebtedness (mortgages, tax liens, judgments, etc.) 2. Charges for prorated items such as interest and taxes through the effective date of the contract of sale between you and the RMC or through the vacate date, whichever is later. 3. Concessions to which you agreed as the seller. 4. Costs for deferred maintenance/repairs to be completed before the home can be purchased. 5. A vacate holdback of $500, refundable to you after you have permanently vacated the property and the RMC has verified property condition. | ||||
The difference is: | The net equity under the Company relocation program. |
Guaranteed Purchase Offer |
Equity Advance |
New Home Finding Assistance |
Lender Referral |
Home Purchase Closing Costs |
Household Goods Moving |
Temporary Living Expenses |
Final Trip |
Expense Reporting |
Tax Liability on Relocation Expenses Paid to You or On Your Behalf |
The LTIP and Other Agreements | This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LT | ||||
Grant of Restricted Stock Units | PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement, in respect of services to be performed from the Date of Grant. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP. | ||||
Vesting of Restricted Stock Units | In general, provided that you have not had a Separation from Service, your Restricted Stock Units will vest on the earlier of (i) May 22, 2021 or (ii) the date of the 2021 annual meeting of shareholders (or other annual election of shareholders) (such earlier date, the “Normal Vesting Date”). As set forth elsewhere in this Agreement, the Restricted Stock Units may vest earlier upon the occurrence of certain events | ||||
Dividends | Your Restricted Stock Unit account will be credited quarterly on each dividend payment date with additional Restricted Stock Units (including fractions computed to three decimal places), determined by dividing (1) the amount of cash dividends paid on the number of shares of PG&E Corporation common stock represented by the Restricted Stock Units previously credited to your Restricted Stock Unit account by (2) the Fair Market Value of a share of PG&E Corporation common stock on the dividend payment date. Such additional Restricted Stock Units will be subject to the same terms and conditions and will be settled in the same manner and at the same time as the Restricted Stock Units covered by this Agreement | ||||
Settlement | Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock (a “Share”), rounded down to the nearest whole Share. PG&E Corporation will issue Shares in settlement of vested Restricted Stock Units upon the earliest of (1) May 22, 2021 (the “Normal Settlement Date”), (2) your Disability (as defined under Section 409A of the Code), (3) your death, or (4) your Separation from Service following a Change in Control | ||||
Separation of Service | If you have a Separation from Service, whether voluntarily or involuntarily, before the Normal Vesting Date, all Restricted Stock Units subject to this Agreement that have not vested on account of your death, Disability (within the meaning of Section 409A of the Code), or because you for any reason ceased to be on the Board (other than resignation) following a Change in Control will be automatically cancelled and forfeited; provided, however, that if you have a Separation from Service due to a pending Disability determination, forfeiture will not occur until a finding that such Disability has not occurred. | ||||
Death/Disability | In the event of your Disability (as defined in Section 409A of the Code) or death, all Restricted Stock Units credited to your account under this Agreement will immediately become fully vested and be settled in accordance with the settlement provisions described above. |
Change in Control | In the event you cease to be on the Board for any reason (other than resignation) following the occurrence of a Change in Control, all Restricted Stock Units credited to your account under this Agreement will immediately become fully vested and be settled in accordance with the settlement provisions described above. | ||||
Delay | PG&E Corporation will delay the issuance of any Shares to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain “key employees” of certain publicly traded companies); in such event, any Shares to which you would otherwise be entitled during the six (6) month period following the date of your Separation from Service (or shorter period ending on the date of your death following such Separation from Service) will instead be issued on the first business day following the expiration of the applicable delay period. | ||||
Withholding Taxes | PG&E Corporation generally will not be required to withhold taxes on taxable income recognized by you upon settlement of your Restricted Stock Units. However, any taxes that are required to be withheld will be payable by you in cash, by check, or through deductions from your compensation. Also, the Board may, in its discretion and subject to such restrictions as the Board may impose, permit you to satisfy such tax withholding obligations by electing to have PG&E Corporation withhold otherwise deliverable Shares having a fair market value equal to the amount that would be required to be withheld. | ||||
Voting and Other Rights | You will not have voting rights with respect to the Restricted Stock Units until the date the underlying Shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent). | ||||
Applicable Law | This Agreement will be interpreted and enforced under the laws of the State of California. |
The LTIP and Other Agreements | This Agreement and the above cover sheet constitute the entire understanding between you and PG&E Corporation regarding the Performance Shares, subject to the terms of the LTIP. Any prior agreements, commitments or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement or the above cover sheet and the LTIP, the LTIP will govern. Capitalized terms that are not defined in this Agreement or the above cover sheet are defined in the LTIP. In the event of any conflict between the provisions of this Agreement or the above cover sheet and the PG&E Corporation 2012 Officer Severance Policy, this Agreement or the above cover sheet will govern, as applicable. The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation means employment with any member of the Participating Company Group. | ||||
Grant of Performance Shares | PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement (the “Performance Shares”). The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP. | ||||
Vesting of Performance Shares Settlement in Shares/ Performance Goals | As long as you remain in service with PG&E Corporation (which includes service on the PG&E Corporation Board of Directors), the Performance Shares will vest upon, and to the extent of, the Committee’s certification of the extent to which performance goals have been attained for this award as of December 31, 2020 (the “Vesting Date”), which certification will occur on or after January 1, 2021 but before March 15, 2021. Except as described below, all Performance Shares that have not vested will be cancelled upon termination of your service with PG&E Corporation. Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by (a) a proration factor reflecting the number of months you worked during 2020 and (b) the “payout percentage” determined as follows (except as set forth elsewhere in this Agreement), rounded to the nearest whole number. The Performance Shares have performance goals consistent with those in the 2020 Short Term Incentive Plan, and as set forth in Exhibit A. The resulting payout percentage will be based on the achievement of the applicable performance goals as measured over the period January 1, 2020 through December 31, 2020. Achievement of the Performance Shares’ performance goals will be certified by the Committee. Subject to rounding considerations, if performance is below threshold, the payout percentage will be 0%; if performance is at threshold, the payout percentage will be 50%; if performance is at target, the payout percentage will be 100%; and if performance is at or better than maximum, the payout percentage will be 200%. The actual payout percentage for performance between threshold and maximum will be determined based on linear interpolation between the payout percentages for threshold and target, or target and maximum, as appropriate. The final score will be determined in the discretion of the PG&E Corporation Board of Directors or its delegate, including any decision to reduce or forego payment entirely. | ||||
The final payout percentage, if any, will be determined as soon as practicable following the date that the Committee or an equivalent body certifies the extent to which the performance goals have been attained, pursuant to Section 10.5(a) of the LTIP. PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than March 15 of the calendar year following the Vesting Date. |
Dividends | Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement will be accrued on your behalf. If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also will receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. | ||||
Voluntary Termination | If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited. | ||||
Termination for Cause | If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares will be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares will be forfeited. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense, or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation. For the avoidance of doubt, you will not be eligible to retire if your employment is being or is terminated for cause. |
Termination other than for Cause | If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause before the Vesting Date, a portion of your outstanding Performance Shares will vest proportionally based on the number of months prior to the Vesting Date that you were employed by PG&E (rounded down) during 2020. All other outstanding Performance Shares will be cancelled, and any associated accrued dividends will be forfeited, unless your termination of employment was in connection with a Change in Control as provided below. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following the Vesting Date, based on the payout percentage certified by the Committee. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued from the date of grant through the Vesting Date with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. | ||||
Death/Disability | If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares will immediately vest and will be settled, if at all, as soon as practicable after the Vesting Date and no later than March 15 of the year following the Vesting Date, based on the payout percentage certified by the Committee. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued from the date of grant through the Vesting Date with respect to your Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. |
Change in Control | In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation’s rights and obligations under this Agreement or substitutes a substantially equivalent award, Performance Shares will vest on the Vesting Date, and the performance goals will be deemed to have been achieved at target, resulting in a payout percentage of 100%. Settlement will occur as soon as practicable after the Vesting Date and no later than March 15 of the year following the Vesting Date. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares from the date of grant through the Vesting Date multiplied by a payout percentage of 100%. If the Change in Control of PG&E Corporation occurs before the Vesting Date, and if this award is neither so assumed nor so continued by the Acquiror, and the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares will vest and become nonforfeitable on the date of the Change in Control. Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and no later than March 15 of the year following the Vesting Date. The performance goals will be deemed to have been achieved at target and the payout percentage will be 100%. At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by a payout percentage of 100%. | ||||
Termination In Connection with a Change in Control | If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this award) will vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will vest in full and become nonforfeitable as of the date of the Change in Control. Your vested Performance Shares, if any, will be settled as soon as practicable following the original Vesting Date but no later than March 15 of the year following the Vesting Date, based on the payout percentage (which in this case will be deemed to be at target, consistent with the “Change in Control” section, above). At that time you also will receive a cash payment, if any, equal to the amount of dividends accrued from the date of grant through the Vesting Date with respect to your vested Performance Shares multiplied by the same payout percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation has the sole discretion to determine whether termination of your employment was made in connection with a Change in Control. |
Withholding Taxes | The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of your Performance Shares will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Performance Shares determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above. | ||||
Leaves of Absence | For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement. |
No Retention Rights | This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason. | ||||
Recoupment of Awards | Awards are subject to recoupment in accordance with any applicable law and any recoupment policy adopted by the Corporation from time to time, including the PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy, as last revised on February 19, 2019 and available on the PG&E@Work intranet site for the Long-Term Incentive Plan (the policy and location may be changed from time to time by PG&E Corporation). | ||||
Applicable Law | This Agreement will be interpreted and enforced under the laws of the State of California. |
Parent of Significant Subsidiary | Name of Significant Subsidiary | Jurisdiction of Formation of Subsidiary | Names under which Significant Subsidiary does business | |||||||||||||||||
PG&E Corporation | Pacific Gas and Electric Company | CA | Pacific Gas and Electric Company | |||||||||||||||||
PG&E | ||||||||||||||||||||
Pacific Gas and Electric Company | None |
/s/ RAJAT BAHRI | /s/ MICHAEL R. NIGGLI | |||||||||||||||||||||||||
Rajat Bahri | Michael R. Niggli | |||||||||||||||||||||||||
/s/ CHERYL F. CAMPBELL | /s/ PATRICIA K. POPPE | |||||||||||||||||||||||||
Cheryl F. Campbell | Patricia K. Poppe | |||||||||||||||||||||||||
/s/ KERRY W. COOPER | /s/ DEAN L. SEAVERS | |||||||||||||||||||||||||
Kerry W. Cooper | Dean L. Seavers | |||||||||||||||||||||||||
/s/ JESSICA L. DENECOUR | /s/ WILLIAM L. SMITH | |||||||||||||||||||||||||
Jessica L. Denecour | William L. Smith | |||||||||||||||||||||||||
/s/ MARK E. FERGUSON, III | /s/ OLUWADARA J. TRESEDER | |||||||||||||||||||||||||
Mark E. Ferguson, III | Oluwadara J. Treseder | |||||||||||||||||||||||||
/s/ ROBERT C. FLEXON | /s/ BENJAMIN F. WILSON | |||||||||||||||||||||||||
Robert C. Flexon | Benjamin F. Wilson | |||||||||||||||||||||||||
/s/ W. CRAIG FUGATE | /s/ JOHN M. WOOLARD | |||||||||||||||||||||||||
W. Craig Fugate | John M. Woolard | |||||||||||||||||||||||||
/s/ ARNO L. HARRIS | ||||||||||||||||||||||||||
Arno L. Harris |
/s/ RAJAT BAHRI | /s/ MICHAEL R. NIGGLI | |||||||||||||||||||||||||
Rajat Bahri | Michael R. Niggli | |||||||||||||||||||||||||
/s/ CHERYL F. CAMPBELL | /s/ PATRICIA K. POPPE | |||||||||||||||||||||||||
Cheryl F. Campbell | Patricia K. Poppe | |||||||||||||||||||||||||
/s/ KERRY W. COOPER | /s/ DEAN L. SEAVERS | |||||||||||||||||||||||||
Kerry W. Cooper | Dean L. Seavers | |||||||||||||||||||||||||
/s/ JESSICA L. DENECOUR | /s/ WILLIAM L. SMITH | |||||||||||||||||||||||||
Jessica L. Denecour | William L. Smith | |||||||||||||||||||||||||
/s/ MARK E. FERGUSON, III | /s/ OLUWADARA J. TRESEDER | |||||||||||||||||||||||||
Mark E. Ferguson, III | Oluwadara J. Treseder | |||||||||||||||||||||||||
/s/ ROBERT C. FLEXON | /s/ BENJAMIN F. WILSON | |||||||||||||||||||||||||
Robert C. Flexon | Benjamin F. Wilson | |||||||||||||||||||||||||
/s/ W. CRAIG FUGATE | /s/ JOHN M. WOOLARD | |||||||||||||||||||||||||
W. Craig Fugate | John M. Woolard | |||||||||||||||||||||||||
/s/ ARNO L. HARRIS | /s/ ADAM L. WRIGHT | |||||||||||||||||||||||||
Arno L. Harris | Adam. L. Wright | |||||||||||||||||||||||||
Date: February 25, 2021 | /s/ PATRICIA K. POPPE | ||||
Patricia K. Poppe | |||||
Chief Executive Officer |
Date: February 25, 2021 | /s/ CHRISTOPHER A. FOSTER | ||||
Christopher A. Foster | |||||
Vice President and Interim Chief Financial Officer |
Date: February 25, 2021 | /s/ ADAM L. WRIGHT | ||||
Adam L. Wright | |||||
Executive Vice President, Operations and Chief Operating Officer |
Date: February 25, 2021 | /s/ DAVID S. THOMASON | ||||
David S. Thomason | |||||
Vice President, Chief Financial Officer and Controller |
/s/ PATRICIA K. POPPE | |||||
Patricia K. Poppe | |||||
Chief Executive Officer |
/s/ CHRISTOPHER A. FOSTER | |||||
Christopher A. Foster | |||||
Vice President and Interim Chief Financial Officer |
/s/ ADAM L. WRIGHT | |||||
Adam L. Wright | |||||
Executive Vice President, Operations and Chief Operating Officer |
/s/ DAVID S. THOMASON | |||||
David S. Thomason | |||||
Vice President, Chief Financial Officer and Controller |
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CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Operating Revenues | |||
Total operating revenues | $ 18,469 | $ 17,129 | $ 16,759 |
Operating Expenses | |||
Operating and maintenance | 8,684 | 8,725 | 7,153 |
Wildfire-related claims, net of insurance recoveries | 251 | 11,435 | 11,771 |
Wildfire fund expense | 413 | 0 | 0 |
Depreciation, amortization, and decommissioning | 3,468 | 3,234 | 3,036 |
Total operating expenses | 16,714 | 27,223 | 26,459 |
Operating Income (Loss) | 1,755 | (10,094) | (9,700) |
Interest income | 39 | 82 | 76 |
Interest expense | (1,260) | (934) | (929) |
Other income, net | 483 | 250 | 424 |
Reorganization items, net | (1,959) | (346) | 0 |
Loss Before Income Taxes | (942) | (11,042) | (10,129) |
Income tax provision (benefit) | 362 | (3,400) | (3,292) |
Net Loss | (1,304) | (7,642) | (6,837) |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Loss Attributable to Common Shareholders | $ (1,318) | $ (7,656) | $ (6,851) |
Weighted Average Common Shares Outstanding, Basic (in shares) | 1,257 | 528 | 517 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 1,257 | 528 | 517 |
Net Loss Per Common Share, Basic (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Net Loss Per Common Share, Diluted (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | $ 18,469 | $ 17,129 | $ 16,760 |
Operating Expenses | |||
Operating and maintenance | 8,707 | 8,750 | 7,153 |
Wildfire-related claims, net of insurance recoveries | 251 | 11,435 | 11,771 |
Wildfire fund expense | 413 | 0 | 0 |
Depreciation, amortization, and decommissioning | 3,469 | 3,233 | 3,036 |
Total operating expenses | 16,738 | 27,247 | 26,459 |
Operating Income (Loss) | 1,731 | (10,118) | (9,699) |
Interest income | 39 | 82 | 74 |
Interest expense | (1,111) | (912) | (914) |
Other income, net | 470 | 239 | 426 |
Reorganization items, net | (310) | (320) | 0 |
Loss Before Income Taxes | 819 | (11,029) | (10,113) |
Income tax provision (benefit) | 408 | (3,407) | (3,295) |
Net Loss | 411 | (7,622) | (6,818) |
Preferred stock dividend requirement | 14 | 14 | 14 |
Loss Attributable to Common Shareholders | 397 | (7,636) | (6,832) |
Electric | |||
Operating Revenues | |||
Total operating revenues | 13,858 | 12,740 | 12,713 |
Operating Expenses | |||
Cost of goods | 3,116 | 3,095 | 3,828 |
Electric | Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | 13,858 | 12,740 | 12,713 |
Operating Expenses | |||
Cost of goods | 3,116 | 3,095 | 3,828 |
Natural gas | |||
Operating Revenues | |||
Total operating revenues | 4,611 | 4,389 | 4,046 |
Operating Expenses | |||
Cost of goods | 782 | 734 | 671 |
Natural gas | Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | 4,611 | 4,389 | 4,047 |
Operating Expenses | |||
Cost of goods | $ 782 | $ 734 | $ 671 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Net Loss | $ (1,304) | $ (7,642) | $ (6,837) |
Other Comprehensive Income (Loss) | |||
Pension and other postretirement benefit plans obligations | (17) | (1) | 4 |
Total other comprehensive income (loss) | (17) | (1) | 4 |
Comprehensive Loss | (1,321) | (7,643) | (6,833) |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Comprehensive Loss Attributable to Common Shareholders | (1,335) | (7,657) | (6,847) |
Pacific Gas & Electric Co (Utility) | |||
Net Loss | 411 | (7,622) | (6,818) |
Other Comprehensive Income (Loss) | |||
Pension and other postretirement benefit plans obligations | (6) | 2 | (5) |
Total other comprehensive income (loss) | (6) | 2 | (5) |
Comprehensive Loss | $ 405 | $ (7,620) | $ (6,823) |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Pension and other postretirement benefit plans obligations, tax | $ 7 | $ 0 | $ 2 |
Pacific Gas & Electric Co (Utility) | |||
Pension and other postretirement benefit plans obligations, tax | $ 2 | $ 1 | $ 2 |
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Current Assets | ||
Cash and cash equivalents | $ 484 | $ 1,570 |
Restricted Cash | 143 | 7 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) | 1,883 | 1,287 |
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) | 1,083 | 969 |
Regulatory balancing accounts | 2,001 | 2,114 |
Other | 1,172 | 2,617 |
Regulatory assets | 410 | 315 |
Inventories | ||
Gas stored underground and fuel oil | 95 | 97 |
Materials and supplies | 533 | 550 |
Wildfire fund asset | 464 | 0 |
Other | 1,334 | 639 |
Total current assets | 9,602 | 10,165 |
Property, Plant, and Equipment | ||
Electric | 66,982 | 62,707 |
Gas | 24,135 | 22,688 |
Construction work in progress | 2,757 | 2,675 |
Other | 20 | 20 |
Total property, plant, and equipment | 93,894 | 88,090 |
Accumulated depreciation | (27,758) | (26,455) |
Net property, plant, and equipment | 66,136 | 61,635 |
Other Noncurrent Assets | ||
Regulatory assets | 8,978 | 6,066 |
Nuclear decommissioning trusts | 3,538 | 3,173 |
Operating lease right of use asset | 1,741 | 2,286 |
Wildfire fund asset | 5,816 | 0 |
Income taxes receivable | 67 | 67 |
Other | 1,978 | 1,804 |
Total other noncurrent assets | 22,118 | 13,396 |
TOTAL ASSETS | 97,856 | 85,196 |
Current Liabilities | ||
Short-term borrowings | 3,547 | 0 |
Long-term debt, classified as current | 28 | 0 |
Debtor-in-possession financing, classified as current | 0 | 1,500 |
Accounts payable | ||
Trade creditors | 2,402 | 1,954 |
Regulatory balancing accounts | 1,245 | 1,797 |
Other | 580 | 566 |
Operating lease liabilities | 533 | 556 |
Disputed claims and customer refunds | 242 | 0 |
Interest payable | 498 | 4 |
Wildfire-related claims | 2,250 | 0 |
Other | 2,256 | 1,254 |
Total current liabilities | 13,581 | 7,631 |
Noncurrent Liabilities | ||
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) | 37,288 | 0 |
Regulatory liabilities | 10,424 | 9,270 |
Pension and other postretirement benefits | 2,444 | 1,884 |
Asset retirement obligations | 6,412 | 5,854 |
Deferred income taxes | 1,398 | 320 |
Operating lease liabilities | 1,208 | 1,730 |
Other | 3,848 | 2,573 |
Total noncurrent liabilities | 63,022 | 21,631 |
Liabilities Subject to Compromise | 0 | 50,546 |
Contingencies and Commitments | ||
Shareholders' Equity | ||
Common stock, no par value | 30,224 | 13,038 |
Reinvested earnings | (9,196) | (7,892) |
Accumulated other comprehensive income | (27) | (10) |
Total shareholders' equity | 21,001 | 5,136 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 21,253 | 5,388 |
TOTAL LIABILITIES AND EQUITY | 97,856 | 85,196 |
Pacific Gas & Electric Co (Utility) | ||
Current Assets | ||
Cash and cash equivalents | 261 | 1,122 |
Restricted Cash | 143 | 7 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) | 1,883 | 1,287 |
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) | 1,083 | 969 |
Regulatory balancing accounts | 2,001 | 2,114 |
Other | 1,180 | 2,647 |
Regulatory assets | 410 | 315 |
Inventories | ||
Gas stored underground and fuel oil | 95 | 97 |
Materials and supplies | 533 | 550 |
Wildfire fund asset | 464 | 0 |
Other | 1,321 | 628 |
Total current assets | 9,374 | 9,736 |
Property, Plant, and Equipment | ||
Electric | 66,982 | 62,707 |
Gas | 24,135 | 22,688 |
Construction work in progress | 2,757 | 2,675 |
Other | 18 | 18 |
Total property, plant, and equipment | 93,892 | 88,088 |
Accumulated depreciation | (27,756) | (26,453) |
Net property, plant, and equipment | 66,136 | 61,635 |
Other Noncurrent Assets | ||
Regulatory assets | 8,978 | 6,066 |
Nuclear decommissioning trusts | 3,538 | 3,173 |
Operating lease right of use asset | 1,736 | 2,279 |
Wildfire fund asset | 5,816 | 0 |
Income taxes receivable | 66 | 66 |
Other | 1,818 | 1,659 |
Total other noncurrent assets | 21,952 | 13,243 |
TOTAL ASSETS | 97,462 | 84,614 |
Current Liabilities | ||
Short-term borrowings | 3,547 | 0 |
Debtor-in-possession financing, classified as current | 0 | 1,500 |
Accounts payable | ||
Trade creditors | 2,366 | 1,949 |
Regulatory balancing accounts | 1,245 | 1,797 |
Other | 624 | 675 |
Operating lease liabilities | 530 | 553 |
Disputed claims and customer refunds | 242 | 0 |
Interest payable | 444 | 4 |
Wildfire-related claims | 2,250 | 0 |
Other | 2,248 | 1,263 |
Total current liabilities | 13,496 | 7,741 |
Noncurrent Liabilities | ||
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) | 32,664 | 0 |
Regulatory liabilities | 10,424 | 9,270 |
Pension and other postretirement benefits | 2,328 | 1,884 |
Asset retirement obligations | 6,412 | 5,854 |
Deferred income taxes | 1,570 | 442 |
Operating lease liabilities | 1,206 | 1,726 |
Other | 3,886 | 2,626 |
Total noncurrent liabilities | 58,490 | 21,802 |
Liabilities Subject to Compromise | 0 | 49,736 |
Contingencies and Commitments | ||
Shareholders' Equity | ||
Preferred stock | 258 | 258 |
Common stock, no par value | 1,322 | 1,322 |
Additional paid-in capital | 28,286 | 8,550 |
Reinvested earnings | (4,385) | (4,796) |
Accumulated other comprehensive income | (5) | 1 |
Total shareholders' equity | 25,476 | 5,335 |
TOTAL LIABILITIES AND EQUITY | $ 97,462 | $ 84,614 |
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Allowance for doubtful accounts | $ 146 | $ 43 |
Customers, VIE | 1,630 | 0 |
Allowance for doubtful accounts, customers, VIE | 143 | 0 |
Accrued unbilled revenue | 959 | 0 |
Short-term borrowings, VIE | $ 1,000 | $ 0 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 3,600,000,000 | 800,000,000 |
Common stock, shares outstanding (in shares) | 1,984,678,673 | 529,236,741 |
Pacific Gas & Electric Co (Utility) | ||
Allowance for doubtful accounts | $ 146 | $ 43 |
Customers, VIE | 1,630 | 0 |
Allowance for doubtful accounts, customers, VIE | 143 | 0 |
Accrued unbilled revenue | 959 | 0 |
Short-term borrowings, VIE | $ 1,000 | $ 0 |
Common stock, par value (in dollars per share) | $ 5 | $ 5 |
Common stock, shares authorized (in shares) | 800,000,000 | 800,000,000 |
Common stock, shares outstanding (in shares) | 264,374,809 | 264,374,809 |
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Cash Flows from Operating Activities | |||
Net income (Loss) | $ (1,304) | $ (7,642) | $ (6,837) |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,468 | 3,234 | 3,036 |
Allowance for equity funds used during construction | (140) | (79) | (129) |
Deferred income taxes and tax credits, net | 1,097 | (2,948) | (2,532) |
Reorganization items, net | 1,458 | 108 | 0 |
Wildfire fund expense | 413 | 0 | 0 |
Disallowed capital expenditures | 17 | 581 | (45) |
Other | 399 | 207 | 332 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (1,182) | (104) | (121) |
Wildfire-related insurance receivable | 1,564 | 35 | (1,698) |
Inventories | 6 | (80) | (73) |
Accounts payable | 58 | 516 | 409 |
Wildfire-related claims | (16,525) | (114) | 13,665 |
Income taxes receivable/payable | 0 | 23 | (23) |
Other current assets and liabilities | (1,079) | 77 | (281) |
Regulatory assets, liabilities, and balancing accounts, net | (2,451) | (1,417) | (800) |
Liabilities subject to compromise | 413 | 12,222 | 0 |
Contributions to wildfire fund | (5,200) | 0 | 0 |
Other noncurrent assets and liabilities | (142) | 197 | (151) |
Net cash provided by (used in) operating activities | (19,130) | 4,816 | 4,752 |
Cash Flows from Investing Activities | |||
Capital expenditures | (7,690) | (6,313) | (6,514) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,518 | 956 | 1,412 |
Purchases of nuclear decommissioning trust investments | (1,590) | (1,032) | (1,485) |
Other | 14 | 11 | 23 |
Net cash used in investing activities | (7,748) | (6,378) | (6,564) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 500 | 1,850 | 0 |
Repayments of debtor-in-possession credit facility | (2,000) | (350) | 0 |
Debtor-in-possession credit facility debt issuance costs | (6) | (113) | 0 |
Bridge facility financing fees | (73) | 0 | 0 |
Repayment of long-term debt | (764) | 0 | (795) |
Borrowings under credit facilities | 8,554 | 0 | 3,960 |
Repayments under credit facilities | (3,949) | 0 | (775) |
Credit facilities financing fees | (22) | 0 | 0 |
Net repayments of commercial paper, net of discount | 0 | 0 | (182) |
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates | 1,448 | 0 | 600 |
Short-term debt matured | 0 | 0 | (750) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs | 13,497 | 0 | 793 |
Exchanged debt financing fees | (103) | 0 | 0 |
Common stock issued | 7,582 | 85 | 200 |
Equity Units issued | 1,304 | 0 | 0 |
Other | (40) | (8) | (20) |
Net cash provided by financing activities | 25,928 | 1,464 | 3,031 |
Net change in cash, cash equivalents, and restricted cash | (950) | (98) | 1,219 |
Cash, cash equivalents, and restricted cash at January 1 | 1,577 | 1,675 | 456 |
Cash, cash equivalents, and restricted cash at December 31 | 627 | 1,577 | 1,675 |
Less: Restricted cash and restricted cash equivalents | (143) | (7) | (7) |
Cash and cash equivalents at December 31 | 484 | 1,570 | 1,668 |
Cash paid for: | |||
Interest, net of amounts capitalized | (1,563) | (10) | (786) |
Income taxes, net | 0 | 0 | (49) |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 515 | 826 | 368 |
Operating lease liabilities arising from obtaining ROU assets | 13 | 2,816 | 0 |
Common stock issued in satisfaction of liabilities | 8,276 | 0 | 0 |
Pacific Gas & Electric Co (Utility) | |||
Cash Flows from Operating Activities | |||
Net income (Loss) | 411 | (7,622) | (6,818) |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,469 | 3,233 | 3,036 |
Allowance for equity funds used during construction | (140) | (79) | (129) |
Deferred income taxes and tax credits, net | 1,141 | (2,952) | (2,548) |
Reorganization items, net | (90) | 97 | 0 |
Wildfire fund expense | 413 | 0 | 0 |
Disallowed capital expenditures | 17 | 581 | (45) |
Other | 370 | 167 | 258 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (1,160) | (132) | (122) |
Wildfire-related insurance receivable | 1,564 | 35 | (1,698) |
Inventories | 6 | (80) | (73) |
Accounts payable | (24) | 579 | 421 |
Wildfire-related claims | (16,525) | (114) | 13,665 |
Income taxes receivable/payable | 0 | 5 | (5) |
Other current assets and liabilities | (1,141) | 101 | (301) |
Regulatory assets, liabilities, and balancing accounts, net | (2,451) | (1,417) | (800) |
Liabilities subject to compromise | 401 | 12,194 | 0 |
Contributions to wildfire fund | (5,200) | 0 | 0 |
Other noncurrent assets and liabilities | (108) | 214 | (137) |
Net cash provided by (used in) operating activities | (19,047) | 4,810 | 4,704 |
Cash Flows from Investing Activities | |||
Capital expenditures | (7,690) | (6,313) | (6,514) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,518 | 956 | 1,412 |
Purchases of nuclear decommissioning trust investments | (1,590) | (1,032) | (1,485) |
Other | 14 | 11 | 23 |
Net cash used in investing activities | (7,748) | (6,378) | (6,564) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 500 | 1,850 | 0 |
Repayments of debtor-in-possession credit facility | (2,000) | (350) | 0 |
Debtor-in-possession credit facility debt issuance costs | (6) | (97) | 0 |
Bridge facility financing fees | (33) | 0 | 0 |
Repayment of long-term debt | (100) | (445) | |
Borrowings under credit facilities | 8,554 | 0 | 3,535 |
Repayments under credit facilities | (3,949) | 0 | (650) |
Credit facilities financing fees | (22) | 0 | 0 |
Net repayments of commercial paper, net of discount | 0 | 0 | (50) |
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates | 1,448 | 0 | 250 |
Short-term debt matured | 0 | 0 | (750) |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs | 8,837 | 0 | 793 |
Exchanged debt financing fees | (103) | 0 | 0 |
Equity contribution from PG&E Corporation | 12,986 | 0 | 45 |
Other | (42) | (8) | (20) |
Net cash provided by financing activities | 26,070 | 1,395 | 2,708 |
Net change in cash, cash equivalents, and restricted cash | (725) | (173) | 848 |
Cash, cash equivalents, and restricted cash at January 1 | 1,129 | 1,302 | 454 |
Cash, cash equivalents, and restricted cash at December 31 | 404 | 1,129 | 1,302 |
Less: Restricted cash and restricted cash equivalents | (143) | (7) | (7) |
Cash and cash equivalents at December 31 | 261 | 1,122 | 1,295 |
Cash paid for: | |||
Interest, net of amounts capitalized | (1,458) | (7) | (773) |
Income taxes, net | 0 | 0 | (59) |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 515 | 826 | 368 |
Operating lease liabilities arising from obtaining ROU assets | 13 | 2,807 | 0 |
Common stock equity infusion from PG&E Corporation used to satisfy liabilities | $ 6,750 | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Cash Flows from Financing Activities | |||
Discount on net issuances of commercial paper | $ 0 | $ 0 | $ 1 |
Issuance costs for short-term debt | 2 | 0 | 0 |
Premium, discount, and issuance costs on proceeds from long-term debt | 178 | 0 | 7 |
Pacific Gas & Electric Co (Utility) | |||
Cash Flows from Financing Activities | |||
Discount on net issuances of commercial paper | 0 | 0 | 0 |
Issuance costs for short-term debt | 2 | 0 | 0 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 88 | $ 0 | $ 7 |
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) |
Total |
Pacific Gas & Electric Co (Utility) |
Preferred Stock
Pacific Gas & Electric Co (Utility)
|
Common Stock |
Common Stock
Pacific Gas & Electric Co (Utility)
|
Additional Paid-in Capital
Pacific Gas & Electric Co (Utility)
|
Reinvested Earnings |
Reinvested Earnings
Pacific Gas & Electric Co (Utility)
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Accumulated Other Comprehensive Loss |
Accumulated Other Comprehensive Loss
Pacific Gas & Electric Co (Utility)
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Total Shareholders' Equity |
Total Shareholders' Equity
Pacific Gas & Electric Co (Utility)
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Non- controlling Interest - Preferred Stock of Subsidiary |
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Beginning balance (in shares) at Dec. 31, 2017 | 514,755,845 | ||||||||||||
Beginning balance at Dec. 31, 2017 | $ 19,472,000,000 | $ 258,000,000 | $ 12,632,000,000 | $ 1,322,000,000 | $ 8,505,000,000 | $ 6,596,000,000 | $ 9,656,000,000 | $ (8,000,000) | $ 6,000,000 | $ 19,220,000,000 | $ 19,747,000,000 | $ 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income (Loss) | (6,837,000,000) | $ (6,818,000,000) | (6,837,000,000) | (6,818,000,000) | (6,837,000,000) | (6,818,000,000) | |||||||
Other comprehensive income (loss) | 4,000,000 | (5,000,000) | 5,000,000 | 2,000,000 | (1,000,000) | (7,000,000) | 4,000,000 | (5,000,000) | |||||
Equity contribution | 45,000,000 | 45,000,000 | |||||||||||
Common stock issued, net (in shares) | 5,582,865 | ||||||||||||
Common stock issued, net | 200,000,000 | $ 200,000,000 | 200,000,000 | ||||||||||
Stock-based compensation amortization | 78,000,000 | $ 78,000,000 | 78,000,000 | ||||||||||
Preferred stock dividend requirement of subsidiary | (14,000,000) | (14,000,000) | (14,000,000) | ||||||||||
Preferred stock dividend | 0 | (14,000,000) | (14,000,000) | ||||||||||
Ending balance (in shares) at Dec. 31, 2018 | 520,338,710 | ||||||||||||
Ending balance at Dec. 31, 2018 | 12,903,000,000 | 258,000,000 | $ 12,910,000,000 | 1,322,000,000 | 8,550,000,000 | (250,000,000) | 2,826,000,000 | (9,000,000) | (1,000,000) | 12,651,000,000 | 12,955,000,000 | 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income (Loss) | (7,642,000,000) | (7,622,000,000) | (7,642,000,000) | (7,622,000,000) | (7,642,000,000) | (7,622,000,000) | |||||||
Other comprehensive income (loss) | (1,000,000) | 2,000,000 | (1,000,000) | 2,000,000 | (1,000,000) | 2,000,000 | |||||||
Common stock issued, net (in shares) | 8,898,031 | ||||||||||||
Common stock issued, net | 85,000,000 | $ 85,000,000 | 85,000,000 | ||||||||||
Stock-based compensation amortization | $ 43,000,000 | $ 43,000,000 | 43,000,000 | ||||||||||
Preferred stock dividend | $ 0 | ||||||||||||
Ending balance (in shares) at Dec. 31, 2019 | 529,236,741 | 264,374,809 | 529,236,741 | ||||||||||
Ending balance at Dec. 31, 2019 | $ 5,388,000,000 | 258,000,000 | $ 13,038,000,000 | 1,322,000,000 | 8,550,000,000 | (7,892,000,000) | (4,796,000,000) | (10,000,000) | 1,000,000 | 5,136,000,000 | 5,335,000,000 | 252,000,000 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income (Loss) | (1,304,000,000) | $ 411,000,000 | (1,304,000,000) | 411,000,000 | (1,304,000,000) | 411,000,000 | |||||||
Other comprehensive income (loss) | (17,000,000) | (6,000,000) | (17,000,000) | (6,000,000) | (17,000,000) | (6,000,000) | |||||||
Equity contribution | 19,736,000,000 | 19,736,000,000 | |||||||||||
Common stock issued, net (in shares) | 1,455,441,932 | ||||||||||||
Common stock issued, net | 15,854,000,000 | $ 15,854,000,000 | 15,854,000,000 | ||||||||||
Equity units issued | 1,304,000,000 | 1,304,000,000 | 1,304,000,000 | ||||||||||
Stock-based compensation amortization | $ 28,000,000 | $ 28,000,000 | 28,000,000 | ||||||||||
Preferred stock dividend | $ 0 | ||||||||||||
Ending balance (in shares) at Dec. 31, 2020 | 1,984,678,673 | 264,374,809 | 1,984,678,673 | ||||||||||
Ending balance at Dec. 31, 2020 | $ 21,253,000,000 | $ 258,000,000 | $ 30,224,000,000 | $ 1,322,000,000 | $ 28,286,000,000 | $ (9,196,000,000) | $ (4,385,000,000) | $ (27,000,000) | $ (5,000,000) | $ 21,001,000,000 | $ 25,476,000,000 | $ 252,000,000 |
ORGANIZATION AND BASIS OF PRESENTATION |
12 Months Ended |
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Dec. 31, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
ORGANIZATION AND BASIS OF PRESENTATION | ORGANIZATION AND BASIS OF PRESENTATION Organization and Basis of Presentation PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. Chapter 11 Filing and Going Concern The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection on January 29, 2019. Uncertainty regarding these matters previously raised substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on the Effective Date of July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date the financial statements were issued. (For more information regarding the Chapter 11 Cases, see Note 2 below.)
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BANKRUPTCY FILING |
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BANKRUPTCY FILING | BANKRUPTCY FILING Chapter 11 Proceedings On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan. Significant Bankruptcy Court Actions Plan of Reorganization and Restructuring Support Agreements On June 19, 2020, PG&E Corporation and the Utility and the Shareholder Proponents filed the Plan. On June 20, 2020, the Bankruptcy Court confirmed the Plan by issuing the Confirmation Order. PG&E Corporation and the Utility emerged from Chapter 11 on the Effective Date of July 1, 2020. On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA with certain holders of wildfire insurance subrogation claims (such claims, the “Subrogation Claims”). On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. As of December 31, 2020, PG&E Corporation and the Utility incurred $53 million in professional fees related to the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 14 for further information on the Subrogation RSA. On December 6, 2019, PG&E Corporation and the Utility entered the TCC RSA, which was subsequently amended on December 16, 2019, with the TCC, the attorneys and other advisors and agents for holders of claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and Public Entity Wildfire Claims (as defined below)) (the “Fire Victim Claims”) that are signatories to the TCC RSA, and the Shareholder Proponents. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 14 for further information on the TCC RSA. On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” therein and the Shareholder Proponents. On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA. Confirmation of the Plan of Reorganization The Plan as confirmed by the Confirmation Order provides for certain transactions and the satisfaction and treatment of claims against and interests in PG&E Corporation and the Utility, each in accordance with the terms of the Plan, including the transactions described below. The Plan provides for the following treatment of various classes of claims as described below. PG&E Corporation and the Utility are in the process of resolving and paying claims pursuant to the treatment provided under the Plan. •PG&E Corporation and the Utility funded the Fire Victim Trust for the benefit of all holders of Fire Victim Claims, whose claims were channeled to the Fire Victim Trust on the Effective Date with no recourse to PG&E Corporation and the Utility. In full and final satisfaction, release, and discharge of all Fire Victim Claims, the Fire Victim Trust was funded with $5.4 billion in cash (with an additional $1.35 billion in cash to be funded on a deferred basis), common stock of PG&E Corporation representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments), plus the assignment of certain rights and causes of action. As a result of such funding, all Fire Victim Claims have been satisfied, released, discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility; •PG&E Corporation and the Utility funded a trust (the “Subrogation Wildfire Trust”) for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. As a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility; •PG&E Corporation and the Utility paid $1.0 billion in cash to certain local public entities (the “Settling Public Entities”) that entered into PSAs with PG&E Corporation and the Utility and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities in full and final satisfaction, release and discharge of such Settling Public Entities’ wildfire related claims; •The following pre-petition notes of the Utility: (a) 3.50% Senior Notes due October 1, 2020; (b) 4.25% Senior Notes due May 15, 2021; (c) 3.25% Senior Notes due September 15, 2021; and (d) 2.45% Senior Notes due August 15, 2022), (collectively, the “Utility Short-Term Senior Notes”); the following pre-petition notes of the Utility: (a) 6.05% Senior Notes due March 1, 2034; (b) 5.80% Senior Notes due March 1, 2037; (c) 6.35% Senior Notes due February 15, 2038; (d) 6.25% Senior Notes due March 1, 2039; (e) 5.40% Senior Notes due January 15, 2040; and (f) 5.125% Senior Notes due November 15, 2043, (collectively, the “Utility Long-Term Senior Notes) and the pre-petition credit agreements of the Utility, including in connection with the pollution control bonds (except for $100 million of pollution control bonds (Series 2008F and 2010E), which were repaid in cash) (collectively, the “Utility Funded Debt”) were refinanced and all other Utility pre-petition senior notes (collectively, the “Utility Reinstated Senior Notes”) were reinstated and collateralized on or around the Effective Date through the issuance of a corresponding series of first mortgage bonds of the Utility; •PG&E Corporation paid in full all of its pre-petition funded debt obligations that were allowed in the Chapter 11 Cases; •PG&E Corporation and the Utility repaid all borrowings under the DIP Facilities and have paid all other allowed administrative expense claims in accordance with the Plan; •Holders of allowed claims by a governmental authority entitled to priority in payment under sections 502(i) and 507(a)(8) of the Bankruptcy Code (“Priority Tax Claims”) have received or will receive in the future, cash in an amount equal to such allowed Priority Tax Claims; •Holders of allowed secured claims other than Priority Tax Claims or secured claims related to the DIP Facilities (“Other Secured Claims”) have received or will receive cash in an amount equal to such Other Secured Claims; •Holders of allowed claims other than administrative expense claims or Priority Tax Claims, entitled to priority in payment as specified in section 507(a)(3), (4), (5), (6), (7), or (9) of the Bankruptcy Code (“Priority Non-Tax Claims”) have received or will receive cash in an amount equal to such allowed Priority Non-Tax Claims; •PG&E Corporation and the Utility will pay in full all pre-petition unsecured claims that do not fall within any of the other classes of unsecured claims under the Plan (“General Unsecured Claims”) that are allowed in the Chapter 11 Cases; and •PG&E Corporation and the Utility will pay in full all allowed claims that are subject to subordination under section 510(b) of the Bankruptcy Code other than subordinated claims related to the common stock of PG&E Corporation (“Subordinated Debt Claims”). PG&E Corporation will provide to each holder of an allowed claim that relates to the common stock of PG&E Corporation that is subject to subordination under section 510(b) of the Bankruptcy Code (a “HoldCo Rescission or Damage Claim”) a number of shares of PG&E Corporation common stock based on a formula as specified in the Plan that varies depending on when the claimant purchased the affected shares of common stock and reduces the amount of the allowed claim by the amount of insurance proceeds, if any, received by the claimant on account of all or any portion of an allowed HoldCo Rescission or Damage Claim. In addition, the Plan also provides for the following in connection with or following the implementation of the Plan: •Holders of claims related to the 2016 Ghost Ship fire are entitled to pursue their claims against PG&E Corporation and the Utility (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year); •Holders of certain claims may be able to pursue their claims against PG&E Corporation and the Utility, such as administrative expense claims that have not been satisfied or come due by the Effective Date, claims arising from wildfires occurring after the Petition Date that have not been satisfied by the Effective Date (including the 2019 Kincade fire (as defined in Note 14 below)), and claims relating to certain FERC refund proceedings, workers’ compensation benefits and certain environmental claims; •PG&E Corporation or the Utility, as applicable, assumed all of their respective power purchase agreements and community choice aggregation servicing agreements; and •PG&E Corporation or the Utility, as applicable, assumed all of their respective pension obligations, other employee obligations, and collective bargaining agreements with labor. The Confirmation Order contains a channeling injunction that is also in the Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Claims will be from the Subrogation Wildfire Trust and the sole source of recovery for holders of Fire Victim Claims will be from the Fire Victim Trust. The holders of such claims will have no recourse to or claims whatsoever against PG&E Corporation and the Utility or their assets and properties on account of such claims. The Plan as confirmed by the Confirmation Order provides for certain financing transactions as follows: •one or more equity offerings of up to $9.0 billion of gross proceeds in cash through the issuance of common stock and/or other equity and/or equity-linked securities pursuant to one or more offerings and/or private placements; •the issuance of $4.75 billion of new PG&E Corporation debt; •the reinstatement of $9.575 billion of pre-petition debt of the Utility; and •the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of the Utility’s 4.55% Senior Notes due 2030 and 4.95% Senior Notes due 2050 (the “New Utility Long-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (ii) $1.75 billion of the Utility’s 3.45% Senior Notes due 2025 and 3.75% Senior Notes due 2028 (the “New Utility Short-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (iii) $3.9 billion of the Utility’s 3.15% Senior Notes due 2026 and 4.50% Senior Notes due 2040 (the “New Utility Funded Debt Exchange Bonds”) to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date) (see Note 5 below for a description of the debt transactions that occurred on or before the Effective Date). The foregoing financing transactions occurred on or around the Effective Date. On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility paid the first tranche of tax benefits of approximately $758 million pursuant to the Tax Benefits Payment Agreement. Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust (the “Fire Victim Trust Assignment Agreement”), pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477.0 million shares of PG&E Corporation common stock. As a result of the Additional Units Issuance (as described in Note 6 below) on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. Further, on the Effective Date, PG&E Corporation and the Utility funded a $10 million fund established for the benefit of the Supporting Public Entities (refer to “Plan Support Agreements with Public Entities” in Note 14 below) under the PSAs in accordance with the terms of the Plan and the PSAs with the Supporting Public Entities, and also made a payment of $1.0 billion in cash to the public entities who are party to the PSAs with the Supporting Public Entities. Also, on the Effective Date, PG&E Corporation and the Utility funded $100 million to the Subrogation Wildfire Trust and placed the balance of the $11.0 billion in a segregated escrow account established and owned by the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims, which was subsequently paid to the Subrogation Wildfire Trust. Equity Financing In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments. For more information, see Note 6 below. Equity Backstop Commitments and Forward Stock Purchase Agreements As of March 6, 2020, PG&E Corporation entered into Chapter 11 Plan Backstop Commitment Letters (collectively, as amended by the Consent Agreements (as defined below), the “Backstop Commitment Letters”) with the Backstop Parties, pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). As a result of PG&E Corporation emerging from Chapter 11 on July 1, 2020, the Backstop Commitments were not utilized and terminated in accordance with their terms. The commitment premium for the Backstop Commitments was paid in shares (the “Backstop Commitment Premium Shares”) of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119 million shares of PG&E Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12.0 billion). PG&E Corporation issued the Backstop Commitment Premium Shares to the Backstop Parties on the Effective Date in connection with emerging from Chapter 11. On June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of expense related to the Backstop Commitment Premium Shares in Reorganization items, net (as defined below). This amount was primarily based on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing price was $9.03 per share and as a result, PG&E Corporation recorded an additional $19 million expense in the third quarter of 2020. Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters. As of December 31, 2020, PG&E Corporation recorded $49 million in professional fees and related expenses to the Backstop Parties in Reorganization items, net. In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the transactions contemplated by the Plan (the “Offerings”), up to $523 million was issuable pursuant to customary options granted to the underwriters thereof to purchase the Option Securities (as defined below in Note 6). On June 19, 2020, PG&E Corporation entered into the Forward Stock Purchase Agreements with the Backstop Parties. Each Forward Stock Purchase Agreement provided that, subject to certain conditions, the Backstop Party would purchase on the Effective Date, and receive on such settlement date as designated in the Forward Stock Purchase Agreement (the “Settlement Date”) an amount of common stock of PG&E Corporation (such shares, each Backstop Party’s “Greenshoe Backstop Shares”) equal to its pro rata share of the value of the Option Securities not purchased by the underwriters (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount” and all Greenshoe Backstop Purchase Amounts in the aggregate, the “Aggregate Greenshoe Backstop Purchase Amount”), at a price per share equal to the lesser of (i) the lowest per share price of common stock sold on an underwritten basis to the public in an offering of common stock of PG&E Corporation, as disclosed on the cover page of the prospectus or prospectus supplement, and (ii) the price per share payable by the investors party to the Investment Agreement dated as of June 7, 2020 (such lesser price, the “Settlement Price”). The Settlement Price was $9.50 per share. Each Forward Stock Purchase Agreement expired on August 3, 2020. On June 25, 2020, the Backstop Parties funded the Greenshoe Backstop Purchase Amount to PG&E Corporation in the amount of $523 million, which was recorded in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation applied the proceeds of such funding to distributions under the Plan on the Effective Date. On August 3, 2020, PG&E Corporation redeemed $120.5 million of the Forward Stock Purchase Agreements payable in cash as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement (as defined below in Note 6). On August 3, 2020, PG&E Corporation delivered 42.3 million Greenshoe Backstop Shares to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that was not redeemed. Additionally, each Forward Stock Purchase Agreement provided that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation would issue to each Backstop Party its pro rata share of 50 million shares of common stock (such shares, each Backstop Party’s “Additional Backstop Premium Shares”). The Additional Backstop Premium Shares were issued to Backstop Parties on the Effective Date. On June 30, 2020, PG&E Corporation recorded $444 million of expense related to the Additional Backstop Premium Shares in Reorganization items, net. This amount was based primarily on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a result, PG&E Corporation recorded an additional $8 million expense in the third quarter of 2020. Financial Reporting in Reorganization Effective on the Petition Date and up to June 30, 2020, PG&E Corporation and the Utility applied accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that were directly associated with reorganization proceedings must have been reported separately as reorganization items, net in the Consolidated Statements of Income. In addition, the balance sheet must have distinguished pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that were not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that were not debtors in the Chapter 11 Cases in the Consolidated Balance Sheets. LSTC are pre-petition obligations that were not fully secured and had at least a possibility of not being repaid at the full claim amount. Where there was uncertainty about whether a secured claim would be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility classified the entire amount of the claim as LSTC. Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Pursuant to the Plan and Confirmation Order, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date were subject to an injunction and were subject to treatment under the Plan. These claims were reflected as LSTC in the Consolidated Balance Sheets at December 31, 2019. Additional claims may arise for contingencies and other unliquidated and disputed amounts. PG&E Corporation’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy. The Utility’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy. Upon emergence from Chapter 11 on July 1, 2020, PG&E Corporation and the Utility were not required to apply fresh start accounting based on the provisions of ASC 852 since the entity’s reorganization value immediately before the date of confirmation was more than the total of all its post-petition liabilities and allowed claims. Liabilities Subject to Compromise As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities was subject to compromise or other treatment pursuant to the Plan. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are subject to an injunction and will be satisfied pursuant to the Plan and the Chapter 11 claims reconciliation process. Prior to June 30, 2020, pre-petition liabilities that were subject to compromise were required to be reported at the amounts expected to be allowed. Therefore, liabilities subject to compromise as of December 31, 2019 in the table below reflected management’s estimates of amounts expected to be allowed in the Chapter 11 Cases, based upon, among other things, the status of negotiations with creditors. As of June 30, 2020, such amounts were reclassified to current or non-current liabilities in the Condensed Consolidated Balance Sheets, based upon management’s judgment as to the timing for settlement of such liabilities. Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified as of December 31, 2020 consist of the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims,” “customer deposits & advances,” and “other” line items which are mainly due to the adjustment to recorded liabilities. (3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets. (4) As of February 18, 2021, $5 million and $941 million has been repaid by PG&E Corporation and the Utility, respectively. Chapter 11 Claims Process PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including asserted litigation claims, trade creditor claims, non-qualified benefit plan claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order. The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation and the Utility on or after the Effective Date, including, but not limited to, the following: •claims arising after the January 29, 2019 Petition Date that constitute administrative expense claims, which will not be discharged pursuant to the Plan, other than allowed administrative expense claims that have been paid in cash or otherwise satisfied in the ordinary course in an amount equal to the allowed amount of such claim on or prior to the Effective Date; •claims of the Ghost Ship fire litigation (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year); •claims arising out of or based on the 2019 Kincade fire (as defined in Note 14 below), which the California Department of Forestry and Fire Protection has determined was caused by the Utility’s transmission lines; which is currently under investigation by the CPUC and the Sonoma County District Attorney’s Office; and which may also be under investigation by various other entities, including law enforcement agencies; and •certain FERC refund proceedings, workers’ compensation benefits and environmental claims. Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Effective Date, including but not limited to, claims arising from or relating to: •the purported de-energization securities class action filed in October 2019 and amended to add PG&E Corporation in April 2020. For more information on the filing, see Note 14 below; •the purported PSPS class action filed in December 2019 and seeking up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid, was dismissed on April 3, 2020, and subsequently appealed on April 6, 2020. For more information on the filing, see Note 15 below; and •indemnification or contributing claims, including with respect to the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. In addition, claims continue to be pursued against PG&E Corporation and the Utility and certain of their respective current and former directors and officers as well as certain underwriters, in connection with three purported securities class actions, as further described in Note 14 under the heading “Securities Class Action Litigation.” Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. Pursuant to the Plan, on and after the Effective Date, the holders of such claims are entitled to pursue their claims against the Reorganized Utility as if the Chapter 11 Cases had not been commenced. On September 1, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court requesting that the court approve an alternative dispute resolution process for resolving disputed general unsecured claims and appoint a panel of mediators in the process. On September 25, 2020, the court approved the motion and appointed a panel of mediators. The mediators’ role will be to assist various claims through a Standard and Abbreviated Mediation Process. On October 27, 2020, PG&E Corporation and the Utility filed a motion for entry of an order extending deadline for the reorganized debtors to object to claims, requesting an additional 180 days beyond December 31, 2020 to process claims. On November 17, 2020, the Bankruptcy Court entered an order extending the deadline under the Plan for PG&E Corporation and the Utility to object to claims through and including June 26, 2021 (March 31, 2021, for claims held by the United States), without prejudice to the rights of PG&E Corporation and the Utility to seek additional extensions thereof. Reorganization Items, Net Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $102 million and $400 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2020 as compared to $15 million and $223 million for PG&E Corporation and the Utility, respectively, during 2019. Of the $400 million in cash paid for the Utility’s reorganization items, during the year ended December 31, 2020, $35 million in facility fees related to the Backstop Commitment Letters were recorded to a regulatory asset as they were deemed probable of recovery. Reorganization items, net for the year ended December 31, 2020 include the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees. Reorganization items, net from the Petition Date through December 31, 2019 include the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off. Loss Contingencies A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which generally occur every three or four years. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer:
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Cash, Cash Equivalents, and Restricted Cash Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2020, the Utility also holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees. Allowance for Doubtful Accounts Receivable and Credit Losses PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectible customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability. In addition, upon adopting ASU 2016-13, PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. See “Financial Instruments - Credit Losses” below for more information. Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.76% in 2020, 3.80% in 2019, and 3.82% in 2018. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred. AFUDC AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $35 million and $140 million during 2020, $55 million and $79 million during 2019, and $53 million and $129 million during 2018. Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2020 and 2019, including nuclear decommissioning obligations:
The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation accrued was $5.1 billion and $4.9 billion at December 31, 2020 and 2019, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2020 and 2019. Disallowance of Plant Costs PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIE The SPV is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program (as defined in Note 5 below), the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated. The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2020 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2020, the SPV has $2.6 billion of net accounts receivable and has outstanding borrowings of $1.0 billion under the Receivables Securitization Program. Non-Consolidated VIEs Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2020, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2020, it did not consolidate any of them. Contributions to the Wildfire Fund On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of December 31, 2020, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. As of December 31, 2020, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire fund asset, and $5.8 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2020, the Utility recorded amortization and accretion expense of $413 million. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire fund expense in the Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset. AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation results in the estimated number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Starting with a 5-year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness. Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ service territories in 2020 for which the cause is currently unknown and which may in the future be determined to be covered by the Wildfire Fund. At December 31, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund. Other Accounting Policies For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 herein. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2019 consisted of the following:
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.) Recognition of Lease Assets and Liabilities A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2020 and 2019. For the years ended December 31, 2020 and 2019, the Utility made total cash payments, including fixed and variable, of $2.5 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. At December 31, 2020 and 2019, the Utility’s operating leases had a weighted average remaining lease term of 5.7 years and 5.9 years and a weighted average discount rate of 6.2% and 6.2%, respectively. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
At December 31, 2020, the Utility’s future expected operating lease payments were as follows:
Recently Adopted Accounting Standards Intangibles—Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses On Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. As of December 31, 2020, expected credit losses of $150 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded at December 31, 2020, $76 million and $10 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU. Defined Benefit Plans In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for defined benefit plans. PG&E Corporation and the Utility adopted the ASU as of December 31, 2020. The adoption of ASU 2018-14 resulted in elimination of the disclosures of (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the (1) aggregate of the service and interest cost components of net periodic benefit costs and (2) benefit obligation for postretirement health care benefits. Additionally, the adoption of this ASU resulted in new disclosures of (i) the weighted-average interest crediting rates for cash balance plans and (ii) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. These amendments have been applied on a retrospective basis to all periods presented. See Note 12 below for further discussion of PG&E Corporation’s and the Utility’s defined benefit pension plans. Accounting Standards Issued But Not Yet Adopted Income Taxes In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. This ASU became effective for PG&E Corporation and the Utility on January 1, 2021 and will not have a material impact on the Consolidated Financial Statements and the related disclosures. Debt In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.
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Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are comprised of the following:
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. (2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval. (4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval. (6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020. Recovery of WMPMA costs is subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. (10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2020. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through the date of the final 2020 GRC decision as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 17 months, beginning March 1, 2021. (12) The 2020 GRC Decision authorized the Utility to modify the existing one-way VMBA Expense Balancing Account to a two-way balancing account to track the difference between actual and adopted expenses resulting from its routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval. (13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2020, the Utility had recorded an aggregate under-collection of $76 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $8 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval. In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt. Regulatory Liabilities Long-term regulatory liabilities are comprised of the following:
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets. (2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 11 below.) (3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. (4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. Current regulatory balancing accounts receivable and payable are comprised of the following:
The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. The general rate case memorandum accounts track the difference between the revenue requirements in effect on January 1, 2020 and the revenue requirements authorized by the CPUC in the 2020 GRC Decision in December 2020. The VMBA tracks routine and enhanced vegetation management activities. The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2020, there was $93 million in insurance premium costs recorded in Current regulatory assets.
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DEBT |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DEBT | DEBT Debtor-In-Possession Facilities In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPM, as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto. On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11. Credit Facilities The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2020:
(1) Includes a $1.5 billion letter of credit sublimit. (2) This includes a $1.5 billion term loan credit facility with a maturity date of June 30, 2021 and a $1.5 billion term loan credit facility with a maturity date of January 1, 2022. Utility Utility Revolving Credit Facility On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM, and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two -year extensions options. Borrowings under the Utility Revolving Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 1.375% to 2.50% based on the Utility’s credit rating or (2) the base rate plus an applicable margin of 0.375% to 1.50% based on the Utility’s credit rating. In addition to interest on outstanding principal under the Utility Revolving Credit Agreement, the Utility is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.25% to 0.50% per annum depending on the Utility’s credit rating. The Utility Revolving Credit Agreement has a maximum letter of credit sublimit equal to $1.5 billion. The Utility may also pay customary letter of credit fees based on letters of credit issued under the Utility Revolving Credit Agreement. The Utility’s obligations under the Utility Revolving Credit Agreement are secured by the issuance of a first mortgage bond, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds. The Utility Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, and (4) fundamental changes. In addition, the Utility Revolving Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant. In the event of a default by the Utility under the Utility Revolving Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the designated agent may, with the consent of the required lenders (or shall upon the request of the required lenders), declare the amounts outstanding under the Utility Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Agreement become payable immediately. The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary prepayments made by the Utility will not reduce the commitments under the Utility Revolving Credit Agreement. Utility Term Loan Credit Facility On July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent. The credit facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund, in part, transactions contemplated under the Plan. Borrowings under the Utility Term Loan Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 2.00% with respect to the Utility 364-Day Term Loan Facility and 2.25% with respect to the Utility 18-Month Term Loan Facility, or (2) the base rate plus an applicable margin of 1.00% with respect to the Utility 364-Day Term Loan Facility and 1.25% with respect to the Utility 18-Month Term Loan Facility. The Utility’s obligations under the Utility Term Loan Credit Agreement are secured by the issuance of first mortgage bonds, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds. The Utility Term Loan Credit Agreement includes usual and customary provisions for term loan agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) fundamental changes, (5) entering into swap agreements and (6) modifications to the Utility’s mortgage indenture. In addition, the Utility Term Loan Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant. In the event of a default by the Utility under the Utility Term Loan Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Utility Term Loan Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Term Loan Credit Agreement become payable immediately. The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Agreement (with all outstanding term loans made under the Utility 364-Day Term Loan Facility being paid first), subject to certain exceptions, with 100% of the net cash proceeds of certain securitization transactions. The Utility may voluntarily repay outstanding loans under the Utility Term Loan Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Receivables Securitization Program On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The loans under the Receivables Securitization Program bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate. The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable. In general, the proceeds from the sale of the accounts receivable are used by the SPV to pay the purchase price for accounts receivables it acquires from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses. Although the SPV is a wholly owned consolidated subsidiary of the Utility, the SPV is legally separate from the Utility. The assets of the SPV (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program is accounted for as a secured financing. The pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. At December 31, 2020 the Utility had outstanding borrowings of $1.0 billion under the Receivables Securitization Program. PG&E Corporation On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two -year extensions at the option of PG&E Corporation. The proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries. Borrowings under the Corporation Revolving Credit Agreement bear interest based on PG&E Corporation’s election of either (1) LIBOR plus an applicable margin of 3.00% to 4.25% based on PG&E Corporation’s credit rating or (2) the base rate plus an applicable margin of 2.00% to 3.25% based on PG&E Corporation’s credit rating. In addition to interest on outstanding principal under the Corporation Revolving Credit Agreement, PG&E Corporation is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.50% to 0.75% per annum depending on PG&E Corporation’s credit rating. PG&E Corporation’s obligations under the Corporation Revolving Credit Agreement are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. The Corporation Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) investments, (5) dispositions, (6) changes in the nature of business, (7) transactions with affiliates, (8) burdensome agreements, (9) restricted payments, (10) fundamental changes, (11) use of proceeds, (12) entering into swap agreements and (13) the ability to dispose of common stock of the Utility. In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter. In the event of a default by PG&E Corporation under the Corporation Revolving Credit Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Corporation Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Agreement become payable immediately. PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary repayments made by PG&E Corporation will not reduce the commitments under the Corporation Revolving Credit Agreement. On the Effective Date, PG&E Corporation repaid and terminated $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent. Other Short-term Borrowings On November 16, 2020, the Utility completed the sale of $1.45 billion aggregate principal amount of floating rate first mortgage bonds due November 15, 2021. Proceeds from the sale of the mortgage bonds were used for general corporate purposes, including the repayment of borrowings outstanding under the Receivables Securitization Program and borrowings outstanding under the Utility Revolving Credit Facility. Long-Term Debt Utility On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1.0 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2.0 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1.0 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and between the Escrow Agent and the Utility. On July 1, 2020, the net proceeds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan. On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt, as described in the table below. On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first priority lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture. On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated. In addition, on July 1, 2020, the Utility obtained a $1.5 billion 18-month secured term loan under the Utility Term Loan Credit Agreement. For more information, see “Credit Facilities” discussion above. PG&E Corporation On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “PG&E Corporation Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”) with JPM, and other lenders from time to time party thereto (collectively, the “Lenders”), JPM, as Administrative Agent and as Collateral Agent. The proceeds of the PG&E Corporation Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation and subsequently released from escrow on the Effective Date pursuant to the Plan. On February 1, 2021, PG&E Corporation entered into a repricing amendment (the “Repricing Amendment”) with the lenders under the Term Loan Credit Agreement pursuant to which, among other things, the applicable interest rate was reduced. In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the PG&E Corporation Term Loan in an amount equal to $6.875 million on the last business day of each quarter. The PG&E Corporation Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The PG&E Corporation Term Loan bears interest based, at PG&E Corporation’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. The original LIBOR floor was 1.0% but was reduced to 0.5% on February 1, 2021 in connection with the Repricing Amendment. The original ABR floor was 2.0% but was similarly reduced to 1.5% on February 1, 2021 in connection with the Repricing Amendment. ABR will equal the highest of the following: the prime rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus 1.0%. The applicable margin for LIBOR loans is 3.0% (reduced from 4.5% on February 1, 2021 in connection with the Repricing Amendment) and the applicable margin for ABR loans is 2.0% (reduced from 3.5% on February 1, 2021 in connection with the Repricing Amendment). PG&E Corporation may prepay the PG&E Corporation Term Loan in whole, at any time, and in part, from time to time, without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans; provided, however, that any voluntary prepayment, refinancing or repricing of the PG&E Corporation Term Loan in connection with certain repricing transactions that occur on or prior to August 1, 2021 shall be subject to a prepayment premium of 1.0% of the principal amount of the term loans so prepaid, refinanced or repriced. The Term Loan Agreement includes usual and customary covenants for loan agreements of this type, including covenants limiting: (1) liens, (2) mergers, (3) sales of all or substantially all of PG&E Corporation’s assets, and (4) sale and leaseback transactions. In addition, the Term Loan Agreement requires that PG&E Corporation maintain ownership, either directly or indirectly, through one or more subsidiaries, of at least 100% of the outstanding common stock of the Utility. In the event of a default by PG&E Corporation under the Term Loan Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the Administrative Agent may, with the consent of the required Lenders (or upon the request of the required Lenders, shall), declare the amounts outstanding under the Term Loan Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Term Loan Agreement become payable immediately. On the Effective Date, the obligations under the Term Loan Agreement became secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On July 1, 2020, the net proceeds from the PG&E Corporation Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan. Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (the “2030 Notes,” and together with the 2028 Notes, the “Notes”). The proceeds of the Notes were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and PG&E Corporation. Prior to July 1, 2023, in the case of the 2028 Notes, and prior to July 1, 2025, in the case of the 2030 Notes, (i) PG&E Corporation may redeem all or part of the Notes of the applicable series, on any one or more occasions at a redemption price equal to 100% of the principal amount of Notes of such series to be redeemed, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the redemption date or (ii) PG&E Corporation may redeem up to 40% of the aggregate principal amount of the Notes of the applicable series on any one or more occasions at certain specified redemption prices with the net cash proceeds from certain equity offerings. On or after July 1, 2023, in the case of the 2028 Notes, and July 1, 2025, in the case of the 2030 Notes, PG&E Corporation may redeem the Notes of a series at certain specified redemption prices, plus accrued and unpaid interest thereon, if any, to but not including, the applicable redemption date. On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On the Effective Date, PG&E Corporation repaid and terminated $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent. The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2. (2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court. (3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and 2020, respectively. (4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%. (5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%. (6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%. (7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%. (8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%. (9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%. (10) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 5.50%. (11) At December 31, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.70%. (12) At December 31, 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.57%. (13) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 2.44%. (14) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020. (15) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above. (16) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above. (17) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above. (18) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above. Pollution Control Bonds The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities. In accordance with the Plan, on July 1, 2020, the Utility repaid Series 2008 F and 2010 E and exchanged Series 2009 A-B, Series 1996 C, E, F, and 1997 B for first mortgage bonds. Contractual Repayment Schedule PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2020 are reflected in the table below:
(1) At December 31, 2020, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.57%, 1.70% and 2.44% respectively.
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COMMON STOCK AND SHARE-BASED COMPENSATION | COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 1,984,678,673 shares of common stock outstanding at December 31, 2020. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2020. On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. As of the termination date for this agreement, no amounts were outstanding which required repayment. Increase in Authorized Capitalization On June 22, 2020, PG&E Corporation filed Amended Articles of Incorporation with the Secretary of State of California which increased the authorized number of shares of common stock to 3.6 billion and the authorized number of shares of preferred stock to 400 million. Plan Equity Financings In connection with emergence from Chapter 11, in July 2020, PG&E Corporation raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments as described below. PG&E Corporation Investment Agreement On June 7, 2020, PG&E Corporation entered into an Investment Agreement (the “Investment Agreement”) with certain investors (the “Investors”) relating to the issuance and sale to the Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock. Per the Investment Agreement, the price per share was equal to $9.50 per share, which was the public equity offering price in the Common Stock Offering (as defined below in “Equity Offerings”). On July 1, 2020, pursuant to the terms of the Investment Agreement, PG&E Corporation issued to the Investors 342.1 million shares of common stock. The Investors and their affiliates have certain customary registration rights with respect to the Shares held by such Investor pursuant to the terms of the Investment Agreement. Equity Offerings On June 25, 2020, PG&E Corporation priced (i) the Common Stock Offering of 423.4 million shares of its common stock, and (ii) the concurrent Equity Units Offering of 14.5 million of its Equity Units, for total net proceeds to PG&E Corporation, after deducting the underwriting discounts and before estimated offering expenses payable by the PG&E Corporation, of $3.97 billion and $1.19 billion, respectively. On June 25, 2020, in connection with the Common Stock Offering, PG&E Corporation entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of several underwriters named in the Common Stock Underwriting Agreement (the “Common Stock Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 423.4 million shares of its common stock to the Common Stock Underwriters. In addition, on June 25, 2020, PG&E Corporation entered into an underwriting agreement (the “Equity Units Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Equity Units Underwriting Agreement (the “Equity Units Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 14.5 million prepaid forward stock purchase contracts (the “Purchase Contracts”) to the Equity Underwriters in order for the Equity Units Underwriters to sell 14.5 million Equity Units. In connection with the Common Stock Offering and pursuant to the Common Stock Underwriting Agreement, PG&E Corporation granted the underwriters a 30-day over-allotment option to purchase up to an additional 42.3 million shares of common stock. In addition, in connection with the Equity Units Offering and pursuant to the Equity Units Underwriting Agreement, PG&E Corporation also granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.45 million Purchase Contracts to be used by the Equity Units Underwriters to create up to an additional 1.45 million Equity Units (together with the 42.3 million shares of common stock, the “Option Securities”). The Common Stock Offering and the Equity Units Offering closed on July 1, 2020, and PG&E Corporation issued and sold a total of 423.4 million shares of its common stock and 14.5 million Purchase Contracts for total net proceeds of $5.2 billion. On July 24, 2020, the Equity Units Underwriters exercised in full, the over-allotment option in the Equity Units Underwriting Agreement and on August 3, 2020, PG&E Corporation issued and sold 1.45 million Equity Units to the Equity Units Underwriters (the “Additional Units Issuance”). The prepaid forward stock purchase contract portion of the Equity Units issued in the Equity Units Offering and the Additional Units Issuance represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided herein. The settlement date of the purchase contract is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. The Common Stock Underwriters did not exercise their option to purchase any additional shares of common stock. PG&E Corporation applied accounting standards applicable to prepaid forward contracts to purchase common stock in order to determine the proper balance sheet classification for the Equity Units issued and sold during the three months ended, September 30, 2020. The Equity Units are considered a range forward contract, in that the settlement of common stock shares is based on a range of potential settlement outcomes. PG&E Corporation used various inputs, including stock price volatility, and determined that the potential outcomes are predominantly fixed share settlements. As such, PG&E Corporation does not view the Equity Units as an obligation to issue a variable number of shares and has concluded that the Equity Units meet all conditions for equity classification and do not meet any of the other conditions that would result in asset or liability classification. The Equity Units issued and sold are classified as Common stock on PG&E Corporation’s Consolidated Balance Sheet. Equity Backstop Commitments and Forward Stock Purchase Agreements See “Equity Financing” in Note 2 above for discussion of the equity backstop commitments which resulted in total net proceeds of $523 million (of which $120.5 million were returned to the Backstop Parties pursuant to the Forward Stock Purchase Agreements, as described below). In connection with the Additional Units Issuance and pursuant to the terms of the Forward Stock Purchase Agreements, on August 3, 2020, PG&E Corporation (i) redeemed a portion of the rights under the Forward Stock Purchase Agreements to receive shares of Common Stock and returned approximately $120.5 million to the Backstop Parties and (ii) issued and delivered to the Backstop Parties 42.3 million Greenshoe Backstop Shares, representing the unredeemed portion of the Aggregate Greenshoe Backstop Purchase Amount divided by the Settlement Price (without any issuance in respect of fractional shares). Equity Issuances to the Fire Victim Trust On the Effective Date, pursuant to the Plan, the Utility entered into the Fire Victim Trust Assignment Agreement, pursuant to which the Utility transferred to the Fire Victim Trust 477 million shares of common stock of PG&E Corporation. As a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. Cash Contribution to the Utility Pursuant to the Plan On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash to the Utility, which used the funds to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein. Ownership Restrictions in PG&E Corporation’s Amended Articles Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code. In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility issued to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. The shares transferred to the Fire Victim Trust were valued at $4.53 billion on the date of transfer, $2.2 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust. In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of December 31, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. PG&E Corporation expects to elect grantor trust treatment, subject to entering into a definitive agreement with the Fire Victim Trust. There can be no assurance that such an agreement will be reached or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur only at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were contributed to the Fire Victim Trust. Dividends On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018. On April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s WMP. On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020. In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, -year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11. Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of December 31, 2020, it is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock. Long-Term Incentive Plan The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. As of the Effective Date, the LTIP was amended to increase the maximum number of shares of PG&E Corporation common stock reserved for issuance under the LTIP from 17 million shares to 47 million (subject to certain adjustments), of which 29,174,205 shares were available for future awards at December 31, 2020. The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2020:
Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Stock Options The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2020, $0.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of 0.16 years for PG&E Corporation. The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method in 2019 was $3.87 per share. No stock options were granted in 2020. The significant assumptions used for shares granted in 2019 were:
Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior. There was no tax benefit recognized from stock options for the year ended December 31, 2020. The following table summarizes stock option activity for PG&E Corporation and the Utility for 2020:
(1) Represents additional payout of existing stock option grants. Restricted Stock Units Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2020, 2019, and 2018 was $9.25, $18.57, and $40.92, respectively. The total fair value of restricted stock units that vested during 2020, 2019, and 2018 was $31 million, $42 million, and $41 million, respectively. The tax detriment from restricted stock units that vested in 2020 was $19 million. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2020, $6 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.58 years. The following table summarizes restricted stock unit activity for 2020:
Performance Shares Performance shares generally will vest years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a -year performance period or, for a small number of awards, an internal PG&E Corporation metric. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. Compensation expense attributable to performance shares is generally recognized ratably over the applicable -year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2020, 2019, and 2018 was $9.62, $15.39, and $36.92 respectively. The tax detriment from performance shares that vested in 2020 was $49 million. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2020, $54 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 2.2 years. The following table summarizes activity for performance shares in 2020:
(1) Includes performance shares that expired with zero value as performance targets were not met.
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PREFERRED STOCK |
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Preferred Stock [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding. The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share. At December 31, 2020 and December 31, 2019, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding. At December 31, 2020, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2020, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share. Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid no dividends on preferred stock in 2020, 2019, or 2018.
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EARNINGS PER SHARE |
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EARNINGS PER SHARE | EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2020, 2019, and 2018.
For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
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INCOME TAXES |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
INCOME TAXES | INCOME TAXES PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense. PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
The following tables describe net deferred income tax assets and liabilities:
(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred on PG&E Corporation’s and the Utility’s service territory over the past several years. (2) Amounts include benefits, environmental reserve, and customer advances for construction. (3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (4) Amount primarily includes an environmental reserve. The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
(1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2020, 2019, and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) The Utility includes an adjustment for the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust. PG&E Corporation includes the same adjustment as the Utility and a permanent non-deductible equity backstop premium expense. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively, accounts for the remaining difference. (4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019. Unrecognized Tax Benefits The following table reconciles the changes in unrecognized tax benefits:
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2020 for PG&E Corporation and the Utility was $16 million. PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2020, 2019, and 2018, these amounts were immaterial. Tax Settlements PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. Tax years after 2007 remain subject to examination by the State of California. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards. Other Tax Matters PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2020, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material. As of the date of this report, PG&E Corporation does not believe that it had undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code. In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022. During June 2020, the State of California enacted AB 85, which increases taxes on corporations over a three-year period beginning in 2020 by suspension of the net operating loss deduction and a limit of $5 million per year on business tax credits. PG&E Corporation and the Utility do not anticipate any material impacts to PG&E Corporation’s Consolidated Financial Statements due to this legislation. In December 2020, Congress passed, and the President signed into law the Consolidations and Appropriations Act of 2021. PG&E Corporation and the Utility do not expect this legislation to have a material impact to PG&E Corporation’s Consolidated Financial Statements. See “Ownership Restrictions in PG&E Corporation’s Amended Articles” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 for information on the possible election to treat the Fire Victim Trust as a “grantor trust” for federal income tax purposes.
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DERIVATIVES |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows:
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At December 31, 2020, the Utility’s outstanding derivative balances were as follows:
At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows. Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2020, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
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FAIR VALUE MEASUREMENTS |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: •Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. •Level 2 – Other inputs that are directly or indirectly observable in the marketplace. •Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2020 and 2019. Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Uncertainty Analysis Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. See Note 10 above.
(1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments.
(1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Level 3 Reconciliation The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2020 and 2019, respectively:
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Financial Instruments PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2020 and 2019, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. (2) The fair value of the Utility pre-petition debt was $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5. Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities:
(1) Represents amounts before deducting $671 million and $530 million at December 31, 2020 and 2019, respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows:
The following table provides a summary of activity for the fixed-income and equity securities:
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EMPLOYEE BENEFIT PLANS |
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Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”) PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates. PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans. Change in Plan Assets, Benefit Obligations, and Funded Status The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2020 and 2019: Pension Plan
(1) The actuarial losses for the years ended December 31, 2020 and 2019 were primarily due to a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was also driven by unfavorable changes in the demographic assumptions used to measure the projected benefit obligation. (2) PG&E Corporation’s accumulated benefit obligation was $20.7 billion and $18.4 billion at December 31, 2020 and 2019, respectively. Postretirement Benefits Other than Pensions
(1) The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was primarily due to a decrease in the discount rate used to measure the projected benefit obligation, offset by favorable changes in the demographic assumptions and the elimination of excise tax. (2) At December 31, 2020 and 2019, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $377 million and $343 million as of December 31, 2020, and $337 million and $305 million as of December 31, 2019, respectively. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Net Periodic Benefit Cost PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Accumulated Other Comprehensive Income PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss). Valuation Assumptions The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
The assumed health care cost trend rate as of December 31, 2020 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond. Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 5.1% compares to a ten-year actual return of 9.6%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 835 Aa-grade non-callable bonds at December 31, 2020. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. Investment Policies and Strategies The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments. The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. Fair Value Measurements The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2020 and 2019.
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $249 million and other net liabilities of $99 million at December 31, 2020 and 2019, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days. Short-Term Investments Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets. Global Equity securities The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets. Real Assets The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. Fixed-Income securities Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers Between Levels No material transfers between levels occurred in the years ended December 31, 2020 and 2019. Level 3 Reconciliation The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2020 and 2019:
There were no material transfers out of Level 3 in 2020 and 2019. Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $343 million to the pension benefit plans and $26 million to the other benefit plans in 2020. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2020. The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2021. Benefits Payments and Receipts As of December 31, 2020, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above. Retirement Savings Plan PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $119 million, $109 million, and $105 million in 2020, 2019, and 2018, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation. There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
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RELATED PARTY AGREEMENTS AND TRANSACTIONS |
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RELATED PARTY AGREEMENTS AND TRANSACTIONS | RELATED PARTY AGREEMENTS AND TRANSACTIONS The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies. The Utility’s significant related party transactions were:
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WILDFIRE-RELATED CONTINGENCIES |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
WILDFIRE-RELATED CONTINGENCIES | WILDFIRE-RELATED CONTINGENCIESPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. 2015 Butte Fire In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire. 2018 Camp Fire and 2017 Northern California Wildfires Background According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire. Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities. PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims were satisfied and discharged in accordance with the Plan, as described below. Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.” On January 15, 2021, the Utility paid approximately $758 million of the $1.35 billion, pursuant to the Tax Benefits Payment Agreement. On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees were extinguished in the third quarter of 2020. On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims (as defined below) was satisfied, released and discharged in the third quarter of 2020. Plan Support Agreements with Public Entities On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date. Restructuring Support Agreement with Holders of Subrogation Claims On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also included (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation and the Utility and the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments. As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan was made on the Effective Date. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons. On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized. The Utility has submitted electric incident reports to the CPUC indicating that: •at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose; •various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time; •at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006; •at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and •on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower. On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.) In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Accordingly, PG&E Corporation and the Utility recorded a charge for potential losses in connection with the 2019 Kincade fire in the amount of $625 million for the year ended December 31, 2020 (before available insurance). The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages. The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete. As of February 24, 2021, PG&E Corporation and the Utility are aware of 22 complaints on behalf of approximately 504 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. The petition requests that the cases be coordinated in Sonoma County Superior Court. On December 18, 2020, certain plaintiffs filed a brief in support of PG&E Corporation’s and the Utility’s petition. On December 21, 2020, January 4, 2021 and January 27, 2021, certain plaintiffs filed briefs that supported coordination but requested that the cases be coordinated in San Francisco County Superior Court. On February 2, 2021, pursuant to authorization from the California Judicial Council, a judge of the Sonoma County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for April 2, 2021. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation or the Utility were found to have been negligent. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management. On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that: •wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time; •according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area; •the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes; •on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and •Cal Fire has not issued a determination as to the cause. The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the 2020 Zogg fire. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire and accordingly recorded a pre-tax charge in the amount of $275 million for the quarter ending December 31, 2020 (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above. The aggregate liability of $275 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $275 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal, state, county and local government entities or agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $275 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties. The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $867.5 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for $219 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $275 million probable loss estimate less an initial self-insured retention of $60 million, plus $4 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. As of February 24, 2021, PG&E Corporation and the Utility are aware of six complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent. Loss Recoveries PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. InsuranceInsurance Coverage PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million. In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, 2020, PG&E Corporation and the Utility had prepaid insurance of $536 million, reflected in Other current assets on the Consolidated Balance Sheets. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter will be required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.) Insurance Receivable PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2020, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $219 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance for the 2015 Butte fire and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
Regulatory Recovery On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect. In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires. On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or five percent of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b). Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust. Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. Wildfire-Related Derivative Litigation Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On November 12, 2020, the Trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene. On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al. (now captioned Trotter v. PG&E Corp., et al.), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019. On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al. (now captioned Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. On November 5, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. On February 24, 2021, the Fire Victim Trust filed an amended complaint, alleging two causes of action for breach of fiduciary duty against certain former officers and directors. The first cause of action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires, and the second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire. PG&E Corporation and the Utility are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021. On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 7, 2021. On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al. (now captioned Trotter v. Meserve, et al.), was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan. The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action LitigationWildfire-Related Class Action In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018. Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants. On February 22, 2019, a third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation. On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court. Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims Claims against PG&E Corporation and the Utility relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”). While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows: •each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and •each holder of an allowed Subordinated Debt Claim will receive payment in full in cash. PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows. Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date). The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set. On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 26, 2020. No hearing date has been set. On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviated mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility filed their objection to the Renewed 7023 Motion on October 29, 2020. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline set by the Bankruptcy Court as part of the oral decision to resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion, PG&E Corporation and the Utility filed a revised proposed order, which the Bankruptcy Court entered the same day. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion. De-energization Class Action On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020. On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action. On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter. On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement. The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment. Indemnification Obligations To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors’ and officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases. District Attorneys’ Offices Investigations Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County. On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4). Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire. Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022. On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund. On January 15, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a Trustee and a Claims Administrator. The Court continued the hearing to August 20, 2021 for a further update. Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above. The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information. Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.SEC Investigation On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation. Wildfire Fund under AB 1054 On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund. On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification. The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics (described above). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan. For additional information on the Wildfire Fund, see Note 3 above. OTHER CONTINGENCIES AND COMMITMENTSPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation and the Utility have financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.Enforcement Matters U.S. District Court Matters and Probation In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. CPUC and FERC MattersOrder Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire. As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020. (2) Transmission amounts are under the FERC’s regulatory authority. PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025. On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020. The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan. As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMA as of December 31, 2020 and intends to record the remaining charges of $46 million in 2021. On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition. Transmission Owner Rate Case Revenue Subject to Refund The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for TO18, TO19, and TO20, respectively. On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which the Utility requested rehearing could also impact the revenues recorded for the TO19 and TO20 periods. On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18. The Utility is unable to predict the timing or outcome of the FERC’s decisions in the TO18 proceeding. Other Matters PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $144 million and $116 million at December 31, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at December 31, 2020. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. PSPS Class Action On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously. On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code. On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that the plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.” On April 6, 2020, the plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020. On June 8, 2020, the plaintiff filed its opening brief with the District Court. The Utility filed its opposition brief on July 6, 2020. The plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. On October 20, 2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing. The Utility is unable to determine the timing and outcome of this proceeding. GT&S Capital Expenditures 2011-2014 On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures. On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021. The Utility is unable to determine the timing and outcome of this proceeding. CZU Lightning Complex Fire Notices of Violation Several governmental entities have raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules, the California Coastal Commission alleging violations of the Coastal Act related to unpermitted development in the coastal zone, the Central Coast Regional Water Quality Control Board alleging unpermitted discharge to waters, and the Santa Cruz County Board of Supervisors adopting a resolution to file a complaint with the CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats, and the management of wood debris. The Coastal Commission issued a Notice of Violation letter to the Utility on November 20, 2020, the Central Coast Regional Water Quality Control Board issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued five Notices of Violation through February 8, 2021, and Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues. Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief. Environmental Remediation Contingencies Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor. (2) Primarily driven by Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility’s environmental remediation liability at December 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At December 31, 2020, the Utility expected to recover $986 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates. Hinkley Site The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates. Former Manufactured Gas Plants Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $460 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates. Utility-Owned Generation Facilities and Third-Party Disposal Sites Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates. Fossil Fuel-Fired Generation Sites In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates. Nuclear Insurance The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL. In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.8 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.8 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance. Diablo Canyon Outages Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator are expected to occur during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions. If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC. Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery. The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC. Purchase Commitments The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
Third-Party Power Purchase Agreements In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery. Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2020, renewable energy contracts expire at various dates between 2021 and 2043. Conventional Energy Power Purchase Agreements. The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2020, these power purchase agreements expire at various dates between 2021 and 2033. Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2020, QF contracts in operation expire at various dates between 2021 and 2049. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power. The net costs incurred for all power purchases and electric capacity amounted to $2.9 billion in 2020, $3.0 billion in 2019, and $3.1 billion in 2018. Natural Gas Supply, Transportation, and Storage Commitments The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2021 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads. Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.8 billion in 2020, $0.9 billion in 2019, and $0.6 billion in 2018. Nuclear Fuel Agreements The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2021 and 2024 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. Payments for nuclear fuel amounted to $111 million in 2020, $74 million in 2019, and $73 million in 2018. Other Commitments PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2021 and 2052. At December 31, 2020, the future minimum payments related to these commitments were as follows:
Payments for other commitments amounted to $45 million in 2020, $48 million in 2019, and $43 million in 2018. Certain office facility leases contain escalation clauses requiring annual increases in rent. The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index. There are options to extend these leases for to five years. One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively. The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively. Oakland Headquarters Lease On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020. Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million. The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes. The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023. In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO. At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
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OTHER CONTINGENCIES AND COMMITMENTS |
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
OTHER CONTINGENCIES AND COMMITMENTS | WILDFIRE-RELATED CONTINGENCIESPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. 2015 Butte Fire In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire. 2018 Camp Fire and 2017 Northern California Wildfires Background According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire. Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities. PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims were satisfied and discharged in accordance with the Plan, as described below. Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.” On January 15, 2021, the Utility paid approximately $758 million of the $1.35 billion, pursuant to the Tax Benefits Payment Agreement. On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees were extinguished in the third quarter of 2020. On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims (as defined below) was satisfied, released and discharged in the third quarter of 2020. Plan Support Agreements with Public Entities On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date. Restructuring Support Agreement with Holders of Subrogation Claims On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA. As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also included (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation and the Utility and the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments. As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan was made on the Effective Date. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons. On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized. The Utility has submitted electric incident reports to the CPUC indicating that: •at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose; •various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time; •at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006; •at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and •on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower. On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.) In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Accordingly, PG&E Corporation and the Utility recorded a charge for potential losses in connection with the 2019 Kincade fire in the amount of $625 million for the year ended December 31, 2020 (before available insurance). The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages. The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete. As of February 24, 2021, PG&E Corporation and the Utility are aware of 22 complaints on behalf of approximately 504 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. The petition requests that the cases be coordinated in Sonoma County Superior Court. On December 18, 2020, certain plaintiffs filed a brief in support of PG&E Corporation’s and the Utility’s petition. On December 21, 2020, January 4, 2021 and January 27, 2021, certain plaintiffs filed briefs that supported coordination but requested that the cases be coordinated in San Francisco County Superior Court. On February 2, 2021, pursuant to authorization from the California Judicial Council, a judge of the Sonoma County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for April 2, 2021. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation or the Utility were found to have been negligent. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management. On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that: •wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time; •according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area; •the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes; •on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and •Cal Fire has not issued a determination as to the cause. The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the 2020 Zogg fire. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire and accordingly recorded a pre-tax charge in the amount of $275 million for the quarter ending December 31, 2020 (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above. The aggregate liability of $275 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $275 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal, state, county and local government entities or agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $275 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties. The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $867.5 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for $219 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $275 million probable loss estimate less an initial self-insured retention of $60 million, plus $4 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. As of February 24, 2021, PG&E Corporation and the Utility are aware of six complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent. Loss Recoveries PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. InsuranceInsurance Coverage PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million. In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, 2020, PG&E Corporation and the Utility had prepaid insurance of $536 million, reflected in Other current assets on the Consolidated Balance Sheets. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter will be required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.) Insurance Receivable PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2020, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $219 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance for the 2015 Butte fire and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
Regulatory Recovery On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect. In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires. On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or five percent of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b). Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust. Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. Wildfire-Related Derivative Litigation Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On November 12, 2020, the Trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene. On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al. (now captioned Trotter v. PG&E Corp., et al.), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019. On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al. (now captioned Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. On November 5, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. On February 24, 2021, the Fire Victim Trust filed an amended complaint, alleging two causes of action for breach of fiduciary duty against certain former officers and directors. The first cause of action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires, and the second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire. PG&E Corporation and the Utility are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021. On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 7, 2021. On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al. (now captioned Trotter v. Meserve, et al.), was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021. Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan. The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action LitigationWildfire-Related Class Action In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018. Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants. On February 22, 2019, a third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation. On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court. Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims Claims against PG&E Corporation and the Utility relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”). While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows: •each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and •each holder of an allowed Subordinated Debt Claim will receive payment in full in cash. PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows. Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date). The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set. On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 26, 2020. No hearing date has been set. On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviated mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion. On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility filed their objection to the Renewed 7023 Motion on October 29, 2020. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline set by the Bankruptcy Court as part of the oral decision to resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion, PG&E Corporation and the Utility filed a revised proposed order, which the Bankruptcy Court entered the same day. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion. De-energization Class Action On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020. On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action. On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter. On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement. The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment. Indemnification Obligations To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors’ and officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases. District Attorneys’ Offices Investigations Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County. On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4). Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire. Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022. On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund. On January 15, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a Trustee and a Claims Administrator. The Court continued the hearing to August 20, 2021 for a further update. Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above. The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information. Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.SEC Investigation On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation. Wildfire Fund under AB 1054 On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054. Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund. On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification. The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies. AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics (described above). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge. On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan. For additional information on the Wildfire Fund, see Note 3 above. OTHER CONTINGENCIES AND COMMITMENTSPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation and the Utility have financial commitments described in “Other Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.Enforcement Matters U.S. District Court Matters and Probation In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. CPUC and FERC MattersOrder Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire. As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval. Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020. (2) Transmission amounts are under the FERC’s regulatory authority. PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025. On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020. The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan. As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMA as of December 31, 2020 and intends to record the remaining charges of $46 million in 2021. On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition. Transmission Owner Rate Case Revenue Subject to Refund The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for TO18, TO19, and TO20, respectively. On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which the Utility requested rehearing could also impact the revenues recorded for the TO19 and TO20 periods. On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18. The Utility is unable to predict the timing or outcome of the FERC’s decisions in the TO18 proceeding. Other Matters PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $144 million and $116 million at December 31, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at December 31, 2020. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. PSPS Class Action On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously. On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code. On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that the plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.” On April 6, 2020, the plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020. On June 8, 2020, the plaintiff filed its opening brief with the District Court. The Utility filed its opposition brief on July 6, 2020. The plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. On October 20, 2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing. The Utility is unable to determine the timing and outcome of this proceeding. GT&S Capital Expenditures 2011-2014 On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures. On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021. The Utility is unable to determine the timing and outcome of this proceeding. CZU Lightning Complex Fire Notices of Violation Several governmental entities have raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules, the California Coastal Commission alleging violations of the Coastal Act related to unpermitted development in the coastal zone, the Central Coast Regional Water Quality Control Board alleging unpermitted discharge to waters, and the Santa Cruz County Board of Supervisors adopting a resolution to file a complaint with the CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats, and the management of wood debris. The Coastal Commission issued a Notice of Violation letter to the Utility on November 20, 2020, the Central Coast Regional Water Quality Control Board issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued five Notices of Violation through February 8, 2021, and Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues. Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief. Environmental Remediation Contingencies Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor. (2) Primarily driven by Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility’s environmental remediation liability at December 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At December 31, 2020, the Utility expected to recover $986 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates. Hinkley Site The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates. Former Manufactured Gas Plants Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $460 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates. Utility-Owned Generation Facilities and Third-Party Disposal Sites Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates. Fossil Fuel-Fired Generation Sites In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates. Nuclear Insurance The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL. In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.8 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.8 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance. Diablo Canyon Outages Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator are expected to occur during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions. If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC. Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery. The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC. Purchase Commitments The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
Third-Party Power Purchase Agreements In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery. Renewable Energy Power Purchase Agreements. In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow. As of December 31, 2020, renewable energy contracts expire at various dates between 2021 and 2043. Conventional Energy Power Purchase Agreements. The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2020, these power purchase agreements expire at various dates between 2021 and 2033. Other Power Purchase Agreements. The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2020, QF contracts in operation expire at various dates between 2021 and 2049. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power. The net costs incurred for all power purchases and electric capacity amounted to $2.9 billion in 2020, $3.0 billion in 2019, and $3.1 billion in 2018. Natural Gas Supply, Transportation, and Storage Commitments The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. These agreements expire at various dates between 2021 and 2026. In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads. Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.8 billion in 2020, $0.9 billion in 2019, and $0.6 billion in 2018. Nuclear Fuel Agreements The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2021 and 2024 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. Payments for nuclear fuel amounted to $111 million in 2020, $74 million in 2019, and $73 million in 2018. Other Commitments PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2021 and 2052. At December 31, 2020, the future minimum payments related to these commitments were as follows:
Payments for other commitments amounted to $45 million in 2020, $48 million in 2019, and $43 million in 2018. Certain office facility leases contain escalation clauses requiring annual increases in rent. The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index. There are options to extend these leases for to five years. One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively. The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively. Oakland Headquarters Lease On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020. Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million. The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes. The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023. In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO. At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
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SUBSEQUENT EVENTS |
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Dec. 31, 2020 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS Sale of Transmission Tower Wireless Licenses On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers. The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue. In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million, subject to customary adjustments. SBA paid the Utility $954 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period, resulting in initial cash proceeds of $945 million. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement. The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market potential additional attachment locations on approximately 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.
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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT |
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Condensed Financial Information Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT | PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS
PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions)
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SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS |
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SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | PG&E CORPORATION SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2020, 2019, and 2018
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. PACIFIC GAS AND ELECTRIC COMPANY SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2020, 2019, and 2018
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) |
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Basis of Presentation | This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Use of Estimates and Assumptions | The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies | Loss Contingencies A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.
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Regulation and Regulated Operations | Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
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Revenue Recognition | Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which generally occur every three or four years. The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
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Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents, and Restricted Cash Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2020, the Utility also holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.
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Allowance for Doubtful Accounts Receivable and Credit Losses | Allowance for Doubtful Accounts Receivable and Credit Losses PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectible customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability. In addition, upon adopting ASU 2016-13, PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. See “Financial Instruments - Credit Losses” below for more information.
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Inventories | Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
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Emission Allowances | Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.
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Property, Plant, And Equipment | Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.76% in 2020, 3.80% in 2019, and 3.82% in 2018. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
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AFUDC | AFUDCAFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Decommissioning Obligation | Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation accrued was $5.1 billion and $4.9 billion at December 31, 2020 and 2019, respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2020 and 2019.
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Disallowance of Plant Costs | Disallowance of Plant CostsPG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Decommissioning Trusts | Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
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Variable Interest Entities | Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIE The SPV is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program (as defined in Note 5 below), the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated. The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2020 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2020, the SPV has $2.6 billion of net accounts receivable and has outstanding borrowings of $1.0 billion under the Receivables Securitization Program. Non-Consolidated VIEs Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2020, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2020, it did not consolidate any of them.
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Recognition of Lease Assets and Liabilities | Recognition of Lease Assets and Liabilities A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets.
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Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted | Recently Adopted Accounting Standards Intangibles—Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses On Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. As of December 31, 2020, expected credit losses of $150 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded at December 31, 2020, $76 million and $10 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively. Reference Rate Reform In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU. Defined Benefit Plans In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for defined benefit plans. PG&E Corporation and the Utility adopted the ASU as of December 31, 2020. The adoption of ASU 2018-14 resulted in elimination of the disclosures of (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the (1) aggregate of the service and interest cost components of net periodic benefit costs and (2) benefit obligation for postretirement health care benefits. Additionally, the adoption of this ASU resulted in new disclosures of (i) the weighted-average interest crediting rates for cash balance plans and (ii) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. These amendments have been applied on a retrospective basis to all periods presented. See Note 12 below for further discussion of PG&E Corporation’s and the Utility’s defined benefit pension plans. Accounting Standards Issued But Not Yet Adopted Income Taxes In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. This ASU became effective for PG&E Corporation and the Utility on January 1, 2021 and will not have a material impact on the Consolidated Financial Statements and the related disclosures. Debt In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.
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Earnings Per Share | PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurement | PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: •Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. •Level 2 – Other inputs that are directly or indirectly observable in the marketplace. •Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
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BANKRUPTCY FILING (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Reorganizations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Liabilities Subject To Compromise | Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified as of December 31, 2020 consist of the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims,” “customer deposits & advances,” and “other” line items which are mainly due to the adjustment to recorded liabilities. (3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets. (4) As of February 18, 2021, $5 million and $941 million has been repaid by PG&E Corporation and the Utility, respectively.
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Schedule Of Debtor Reorganization Items | Reorganization items, net for the year ended December 31, 2020 include the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees. Reorganization items, net from the Petition Date through December 31, 2019 include the following:
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) |
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Revenues Disaggregated by Type of Customer | The following table presents the Utility’s revenues disaggregated by type of customer:
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers.
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Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment | The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 15 below.)
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Schedule of Changes in Asset Retirement Obligations | The following table summarizes the changes in ARO liability during 2020 and 2019, including nuclear decommissioning obligations:
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Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income | The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2019 consisted of the following:
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 12 below for additional details.)
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Schedule of Lease Expense | The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
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Schedule of Future Expected Operating Lease Payments | At December 31, 2020, the Utility’s future expected operating lease payments were as follows:
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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables) |
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Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Regulatory Assets | Long-term regulatory assets are comprised of the following:
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. (2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval. (4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval. (6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020. Recovery of WMPMA costs is subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. (10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2020. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through the date of the final 2020 GRC decision as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 17 months, beginning March 1, 2021. (12) The 2020 GRC Decision authorized the Utility to modify the existing one-way VMBA Expense Balancing Account to a two-way balancing account to track the difference between actual and adopted expenses resulting from its routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval. (13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2020, the Utility had recorded an aggregate under-collection of $76 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $8 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
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Long-Term Regulatory Liabilities | Long-term regulatory liabilities are comprised of the following:
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets. (2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 11 below.) (3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. (4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans.
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Current Regulatory Balancing Accounts Receivable | Current regulatory balancing accounts receivable and payable are comprised of the following:
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Current Regulatory Balancing Accounts Payable |
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DEBT (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Line of Credit Facilities | The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2020:
(1) Includes a $1.5 billion letter of credit sublimit. (2) This includes a $1.5 billion term loan credit facility with a maturity date of June 30, 2021 and a $1.5 billion term loan credit facility with a maturity date of January 1, 2022.
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Schedule of Long-term Debt | The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2. (2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court. (3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and 2020, respectively. (4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%. (5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%. (6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%. (7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%. (8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%. (9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%. (10) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 5.50%. (11) At December 31, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.70%. (12) At December 31, 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.57%. (13) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 2.44%. (14) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020. (15) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above. (16) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above. (17) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above. (18) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
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Schedule of Contractual Repayment Schedule | PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2020 are reflected in the table below:
(1) At December 31, 2020, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.57%, 1.70% and 2.44% respectively.
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COMMON STOCK AND SHARE-BASED COMPENSATION (Tables) |
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Common Stock And Share-Based Compensation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Compensation Expense for Share-based Incentive Awards | The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2020:
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Summary of Significant Assumptions Used for Shares Granted | The significant assumptions used for shares granted in 2019 were:
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Summary of Stock Option Activity | The following table summarizes stock option activity for PG&E Corporation and the Utility for 2020:
(1) Represents additional payout of existing stock option grants.
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Schedule of Restricted Stock Units | The following table summarizes restricted stock unit activity for 2020:
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Schedule of Performance Shares | The following table summarizes activity for performance shares in 2020:
(1) Includes performance shares that expired with zero value as performance targets were not met.
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EARNINGS PER SHARE (Tables) |
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings Per Share | The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2020, 2019, and 2018.
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INCOME TAXES (Tables) |
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Income Tax Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
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Schedule of Deferred Tax Assets and Liabilities | The following tables describe net deferred income tax assets and liabilities:
(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred on PG&E Corporation’s and the Utility’s service territory over the past several years. (2) Amounts include benefits, environmental reserve, and customer advances for construction. (3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (4) Amount primarily includes an environmental reserve.
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Schedule of Effective Income Tax Rate Reconciliation | The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
(1) Includes the effect of state flow-through ratemaking treatment. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2020, 2019, and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) The Utility includes an adjustment for the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust. PG&E Corporation includes the same adjustment as the Utility and a permanent non-deductible equity backstop premium expense. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively, accounts for the remaining difference. (4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019.
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Schedule of Change in Unrecognized Tax Benefits | The following table reconciles the changes in unrecognized tax benefits:
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Schedule of Operating Loss and Tax Credit Carryforward Balances | The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
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DERIVATIVES (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Volumes of Outstanding Derivative Contracts | The volumes of the Utility’s outstanding derivatives were as follows:
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
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Outstanding Derivative Balances | At December 31, 2020, the Utility’s outstanding derivative balances were as follows:
At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
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FAIR VALUE MEASUREMENTS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value.
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Uncertainty Analysis |
(1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments.
(1) Represents price per megawatt-hour. (2) Unobservable inputs were weighted by the relative fair value of the instruments.
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Level 3 Reconciliation | The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2020 and 2019, respectively:
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
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Carrying Amount and Fair Value of Financial Instruments | The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. (2) The fair value of the Utility pre-petition debt was $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5.
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Schedule of Unrealized Gains (Losses) Related to Available-for-sale Investments | The following table provides a summary of equity securities and available-for-sale debt securities:
(1) Represents amounts before deducting $671 million and $530 million at December 31, 2020 and 2019, respectively, primarily related to deferred taxes on appreciation of investment value.
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Schedule of Long Term Debt Repayments | The fair value of fixed-income securities by contractual maturity is as follows:
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Schedule of Activity for Debt and Equity Securities | The following table provides a summary of activity for the fixed-income and equity securities:
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EMPLOYEE BENEFIT PLANS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status | The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2020 and 2019: Pension Plan
(1) The actuarial losses for the years ended December 31, 2020 and 2019 were primarily due to a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was also driven by unfavorable changes in the demographic assumptions used to measure the projected benefit obligation. (2) PG&E Corporation’s accumulated benefit obligation was $20.7 billion and $18.4 billion at December 31, 2020 and 2019, respectively. Postretirement Benefits Other than Pensions
(1) The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was primarily due to a decrease in the discount rate used to measure the projected benefit obligation, offset by favorable changes in the demographic assumptions and the elimination of excise tax. (2) At December 31, 2020 and 2019, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $377 million and $343 million as of December 31, 2020, and $337 million and $305 million as of December 31, 2019, respectively.
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Components of Net Periodic Benefit Cost | Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan
(1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
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Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost | The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
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Target Asset Allocation Percentages | The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
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Schedule of Changes in Fair Value of Plan Assets | The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2020 and 2019.
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Schedule of Level 3 Reconciliation | The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2020 and 2019:
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Schedule of Estimated Benefits Expected to be Paid | As of December 31, 2020, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
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RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Significant Related Party Transactions | The Utility’s significant related party transactions were:
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WILDFIRE-RELATED CONTINGENCIES (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Wildfire-Related Claims | The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
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OTHER CONTINGENCIES AND COMMITMENTS (Tables) |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Expense and Capital Expenditures | The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020. (2) Transmission amounts are under the FERC’s regulatory authority.
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Schedule of Environmental Remediation Liability | The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor. (2) Primarily driven by Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant.
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Schedule of Undiscounted Future Expected Power Purchase Agreement Payments | The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
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Schedule of other commitments | At December 31, 2020, the future minimum payments related to these commitments were as follows:
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ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details) |
12 Months Ended |
---|---|
Dec. 31, 2020
numberOfSegment
| |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating segments (segment) | 1 |
BANKRUPTCY FILING (Plan of Reorganization and Restructuring Support Agreements) (Details) - USD ($) |
1 Months Ended | 12 Months Ended | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
Jul. 01, 2020 |
Jun. 25, 2020 |
Sep. 22, 2019 |
Jul. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Jan. 15, 2021 |
Aug. 03, 2020 |
Jun. 12, 2020 |
|
Debt Instrument [Line Items] | ||||||||||
Subrogation claims, professional fees | $ 55,000,000 | |||||||||
Proceeds from issuance or sale of equity | $ 9,000,000,000.0 | $ 3,970,000,000 | $ 9,000,000,000.0 | $ 1,304,000,000 | $ 0 | $ 0 | ||||
Plan of reorganization, tax benefits payment agreement | $ 1,350,000,000 | |||||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000.0 | |||||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | |||||||||
TCC claims settlement, amount | $ 11,000,000,000.0 | $ 11,000,000,000.0 | ||||||||
Subsequent Event | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Payment of plan of reorganization, tax benefits payment agreement | $ 758,000,000 | |||||||||
Settling Public Entities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Litigation payment | 1,000,000,000.0 | |||||||||
Litigation, segregated reimbursement fund | 10,000,000 | |||||||||
Minimum | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Plan of reorganization, tax benefits payment agreement | 650,000,000 | |||||||||
Fire Victim Trust | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Cash contribution by company | $ 5,400,000,000 | |||||||||
Percentage of common stock owned, Fire Victim Trust if common issues additional shares | 22.19% | 22.19% | ||||||||
Litigation payment, fund, cash | $ 5,400,000,000 | |||||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000 | |||||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | |||||||||
Subrogation Wildfire Trust | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Subrogation claims, professional fees | $ 52,000,000 | |||||||||
Litigation payment, fund, cash | 11,000,000,000.0 | |||||||||
Litigation payment, funded | 100,000,000 | |||||||||
New PG&E Corporation Debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 4,750,000,000 | |||||||||
PG&E Corporation | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Proceeds from issuance or sale of equity | 1,304,000,000 | 0 | $ 0 | |||||||
PG&E Corporation | Pre-Petition Debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 9,575,000,000 | |||||||||
PG&E Corporation | New Utility Debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | 23,775,000,000 | |||||||||
PG&E Corporation | New Utility Long-Term Bonds | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 6,200,000,000 | |||||||||
PG&E Corporation | First Mortgage Bonds Due 2030 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.55% | |||||||||
PG&E Corporation | First Mortgage Bonds Due 2050 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.95% | |||||||||
PG&E Corporation | New Utility Short-Term Bonds | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 1,750,000,000 | |||||||||
PG&E Corporation | First Mortgage Bonds Due 2025 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.45% | |||||||||
PG&E Corporation | First Mortgage Bonds Due 2028 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.75% | |||||||||
PG&E Corporation | New Utility Funded Debt Exchange Notes | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 3,900,000,000 | |||||||||
PG&E Corporation | First Mortgage Bonds, Exchange Stated Maturity 2025 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.15% | |||||||||
PG&E Corporation | First Mortgage Bonds, Exchange Stated Maturity 2040 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.50% | |||||||||
PG&E Corporation | New Debt Securities or Bank Debt | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Issuance | $ 11,925,000,000 | |||||||||
Expected repayment | 6,000,000,000.0 | |||||||||
Pacific Gas & Electric Co (Utility) | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Subrogation claims, professional fees | $ 53,000,000 | |||||||||
Plan of reorganization, future tax benefits payment agreement | $ 1,350,000,000 | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due October 2020 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.50% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due May 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.25% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due September 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.25% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due August 2020 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 2.45% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due 2034 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 6.05% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due March 2037 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 5.80% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due February 2038 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 6.35% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due March 2039 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 6.25% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due January 2040 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 5.40% | |||||||||
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due November 2043 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 5.125% | |||||||||
Pacific Gas & Electric Co (Utility) | Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 0.0175% | |||||||||
Pollution control bonds | $ 100,000,000 | $ 0 | $ 100,000,000 | |||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2030 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.55% | |||||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2050 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.95% | |||||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2025 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.45% | |||||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2028 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.75% | |||||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Exchange Stated Maturity 2025 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 3.45% | |||||||||
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Exchange Stated Maturity 2040 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Stated interest rate | 4.50% |
BANKRUPTCY FILING (Equity Financing) (Details) - USD ($) $ / shares in Units, shares in Millions |
1 Months Ended | 12 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Jul. 01, 2020 |
Jun. 25, 2020 |
Jul. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Sep. 30, 2020 |
Aug. 03, 2020 |
Jun. 30, 2020 |
Jun. 19, 2020 |
Mar. 06, 2020 |
|
Debt Instrument [Line Items] | |||||||||||
Equity Units issued | $ 9,000,000,000.0 | $ 3,970,000,000 | $ 9,000,000,000.0 | $ 1,304,000,000 | $ 0 | $ 0 | |||||
Equity backstop commitments, shares (in shares) | 119.0 | ||||||||||
Equity backstop commitments, value | $ 12,000,000,000.0 | ||||||||||
Backstop commitment premium, expense | $ 1,100,000,000 | ||||||||||
Share price (in dollar per share) | $ 9.03 | $ 8.87 | |||||||||
Additional backstop commitment premium, expense | $ 19,000,000 | $ 444,000,000 | |||||||||
Professional legal fees | 34,000,000 | ||||||||||
Professional non-legal fees | 19,000,000 | ||||||||||
Professional fees | 49,000,000 | ||||||||||
Settlement price (in dollars per share) | $ 9.50 | ||||||||||
Additional forward stock purchase agreement, expense | $ 8,000,000 | ||||||||||
Backstop Parties | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Debt commitment letters, required equity funding | $ 12,000,000,000.0 | ||||||||||
Forward stock purchase agreement, common stock issues, pro rata (in shares) | 50.0 | ||||||||||
Offerings | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Equity Units issued | 5,750,000,000 | ||||||||||
Option Amount | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Equity Units issued | $ 523,000,000 | ||||||||||
Common Stock Offering | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Option to purchase additional stock, delivered (in shares) | 42.3 | 42.3 | |||||||||
PG&E Corporation | |||||||||||
Debt Instrument [Line Items] | |||||||||||
Equity Units issued | $ 1,304,000,000 | $ 0 | $ 0 | ||||||||
Forward stock purchase, redemption amount | $ 120,500,000 |
BANKRUPTCY FILING (Schedule of Liabilities Subject to Compromise) (Details) - USD ($) $ in Millions |
6 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2020 |
Dec. 31, 2020 |
Feb. 18, 2021 |
Dec. 31, 2019 |
|
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, beginning balance | $ 23,116.0 | $ 23,116.0 | ||
Wildfire-related claims, beginning balance | 25,548.0 | 25,548.0 | ||
Trade creditors, beginning balance | 1,188.0 | 1,188.0 | ||
Non-qualified benefit plan, beginning balance | 157.0 | 157.0 | ||
2001 bankruptcy disputed claims, beginning balance | 234.0 | 234.0 | ||
Customer deposits & advances, beginning balance | 71.0 | 71.0 | ||
Other, beginning balance | 232.0 | 232.0 | ||
Liabilities Subject to Compromise, beginning balance | 50,546.0 | 50,546.0 | ||
Financing debt, ending balance | 0.0 | |||
Wildfire-related claims, ending balance | 0.0 | |||
Trade creditors, ending balance | 0.0 | |||
Non-qualified benefit plan, ending balance | 0.0 | |||
2001 bankruptcy disputed claims, ending balance | 0.0 | |||
Customer deposits & advances, ending balance | 0.0 | |||
Other, ending balance | 0.0 | |||
Liabilities Subject to Compromise, ending balance | 0.0 | |||
Accounts payable - other | 580.0 | $ 566.0 | ||
Disputed claims and customer refunds | 242.0 | 0.0 | ||
Interest payable | 498.0 | 4.0 | ||
Short-term borrowings | 3,547.0 | 0.0 | ||
Long-term debt, classified as current | 28.0 | 0.0 | ||
Other | 2,256.0 | 1,254.0 | ||
Other non-current liabilities | 3,848.0 | 2,573.0 | ||
Pension and other postretirement benefits | 2,444.0 | 1,884.0 | ||
Accounts payable - trade creditors | 2,402.0 | 1,954.0 | ||
Wildfire-related claims | 2,250.0 | 0.0 | ||
Change in Estimated Allowed Claim | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, change | 351.0 | |||
Wildfire-related claims, change | 18.0 | |||
Trade creditors, change | 6.0 | |||
Non-qualified benefit plan, change | 0.0 | |||
2011 bankruptcy disputed claims, change | 4.0 | |||
Customer deposits & advances, change | 12.0 | |||
Other, change | 59.0 | |||
Liabilities Subject to Compromise, change | 450.0 | |||
Cash Payment | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, change | 0.0 | |||
Wildfire-related claims, change | (23.0) | |||
Trade creditors, change | (14.0) | |||
Non-qualified benefit plan, change | 0.0 | |||
2011 bankruptcy disputed claims, change | 0.0 | |||
Customer deposits & advances, change | 0.0 | |||
Other, change | 0.0 | |||
Liabilities Subject to Compromise, change | (37.0) | |||
Reclassified | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, change | (23,467.0) | |||
Wildfire-related claims, change | (25,543.0) | |||
Trade creditors, change | (1,180.0) | |||
Non-qualified benefit plan, change | (157.0) | |||
2011 bankruptcy disputed claims, change | (238.0) | |||
Customer deposits & advances, change | (83.0) | |||
Other, change | (291.0) | |||
Liabilities Subject to Compromise, change | (50,959.0) | |||
Accounts payable - other | 8.6 | |||
Disputed claims and customer refunds | 237.6 | |||
Interest payable | 1,347.4 | |||
Debt financial instrument | 21,425.7 | |||
Short-term borrowings | 300.0 | |||
Long-term debt, classified as current | 450.0 | |||
Other | 301.0 | |||
Other non-current liabilities | 97.9 | |||
Pension and other postretirement benefits | 121.3 | |||
Accounts payable - trade creditors | 1,126.9 | |||
Wildfire-related claims | 25,542.7 | |||
Pacific Gas & Electric Co (Utility) | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, beginning balance | 22,450.0 | 22,450.0 | ||
Wildfire-related claims, beginning balance | 25,548.0 | 25,548.0 | ||
Trade creditors, beginning balance | 1,183.0 | 1,183.0 | ||
Non-qualified benefit plan, beginning balance | 20.0 | 20.0 | ||
2001 bankruptcy disputed claims, beginning balance | 234.0 | 234.0 | ||
Customer deposits & advances, beginning balance | 71.0 | 71.0 | ||
Other, beginning balance | 230.0 | 230.0 | ||
Liabilities Subject to Compromise, beginning balance | 49,736.0 | 49,736.0 | ||
Financing debt, ending balance | 0.0 | |||
Wildfire-related claims, ending balance | 0.0 | |||
Trade creditors, ending balance | 0.0 | |||
Non-qualified benefit plan, ending balance | 0.0 | |||
2001 bankruptcy disputed claims, ending balance | 0.0 | |||
Customer deposits & advances, ending balance | 0.0 | |||
Other, ending balance | 0.0 | |||
Liabilities Subject to Compromise, ending balance | 0.0 | |||
Accounts payable - other | 624.0 | 675.0 | ||
Disputed claims and customer refunds | 242.0 | 0.0 | ||
Interest payable | 444.0 | 4.0 | ||
Short-term borrowings | 3,547.0 | 0.0 | ||
Other | 2,248.0 | 1,263.0 | ||
Other non-current liabilities | 3,886.0 | 2,626.0 | ||
Pension and other postretirement benefits | 2,328.0 | 1,884.0 | ||
Accounts payable - trade creditors | 2,366.0 | 1,949.0 | ||
Wildfire-related claims | 2,250.0 | 0.0 | ||
Pacific Gas & Electric Co (Utility) | Subsequent Event | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Accounts payable, trade | $ 941.0 | |||
PG&E Corporation | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Financing debt, beginning balance | 666.0 | 666.0 | ||
Wildfire-related claims, beginning balance | 0.0 | 0.0 | ||
Trade creditors, beginning balance | 5.0 | 5.0 | ||
Non-qualified benefit plan, beginning balance | 137.0 | 137.0 | ||
2001 bankruptcy disputed claims, beginning balance | 0.0 | 0.0 | ||
Customer deposits & advances, beginning balance | 0.0 | 0.0 | ||
Other, beginning balance | 2.0 | 2.0 | ||
Liabilities Subject to Compromise, beginning balance | $ 810.0 | 810.0 | ||
Financing debt, ending balance | 0.0 | |||
Wildfire-related claims, ending balance | 0.0 | |||
Trade creditors, ending balance | 0.0 | |||
Non-qualified benefit plan, ending balance | 0.0 | |||
2001 bankruptcy disputed claims, ending balance | 0.0 | |||
Customer deposits & advances, ending balance | 0.0 | |||
Other, ending balance | 0.0 | |||
Liabilities Subject to Compromise, ending balance | 0.0 | |||
Long-term debt, classified as current | 28.0 | 0.0 | ||
Other | 72.0 | 3.0 | ||
Other non-current liabilities | $ 191.0 | $ 58.0 | ||
PG&E Corporation | Subsequent Event | ||||
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward] | ||||
Accounts payable, trade | $ 5.0 |
BANKRUPTCY FILING (Chapter 11 Claims Process) (Details) proofOfClaim in Thousands, claim in Thousands, $ in Billions |
Oct. 27, 2020 |
Dec. 31, 2020
proofOfClaim
lawsuit
claim
|
Dec. 31, 2019
USD ($)
|
---|---|---|---|
Debt Instrument [Line Items] | |||
Proofs of claims | proofOfClaim | 100 | ||
Insurance from wildfire events | $ | $ 2.5 | ||
Deadline extension period | 180 days | ||
Subrogation Wildfire Trust and Fire Victim Trust | |||
Debt Instrument [Line Items] | |||
Proofs of claims | claim | 80 | ||
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt | |||
Debt Instrument [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit | 3 |
BANKRUPTCY FILING (Reorganization Items, Net) (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Pacific Gas & Electric Co (Utility) | ||
Debt Instrument [Line Items] | ||
Payments (refunds) for reorganization items | $ 400 | $ 223 |
Probable of recovery | 35 | |
PG&E Corporation | ||
Debt Instrument [Line Items] | ||
Payments (refunds) for reorganization items | $ 102 | $ 15 |
BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | $ 6 | $ 114 | |
Legal and other | 1,969 | 292 | |
Interest income | (16) | (60) | |
Total reorganization items, net | 1,959 | 346 | $ 0 |
Equity backstop premium expense and bridge loan facility fees | |||
Reorganizations [Line Items] | |||
Legal and other | 1,500 | ||
PG&E Corporation | |||
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | 0 | 17 | |
Legal and other | 1,651 | 19 | |
Interest income | (2) | (10) | |
Total reorganization items, net | 1,649 | 26 | 0 |
Pacific Gas & Electric Co (Utility) | |||
Reorganizations [Line Items] | |||
Debtor-in-possession financing costs | 6 | 97 | |
Legal and other | 318 | 273 | |
Interest income | (14) | (50) | |
Total reorganization items, net | $ 310 | $ 320 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Dec. 31, 2020
USD ($)
numberOfFatality
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
Dec. 30, 2020
USD ($)
|
Oct. 05, 2020
USD ($)
|
Jul. 12, 2019
USD ($)
|
|
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Period for probable revenue recovery | 24 months | |||||
Expected wildfire fund allocation metric, initial contribution | $ 4,800,000,000 | |||||
Expected wildfire fund allocation metric, annual contributions | $ 193,000,000 | |||||
Expected wildfire fund allocation metric, annual contributions, second | $ 193,000,000 | |||||
Litigation liability, current | $ 193,000,000 | |||||
Wildfire fund asset | 464,000,000 | $ 0 | ||||
Litigation contribution, net | 5,800,000,000 | |||||
Amortization and accretion | $ 413,000,000 | 0 | $ 0 | |||
Monte carlo simulation, historical data, period | 12 years | |||||
Amortization period | 6 years | |||||
Percentage assumption change | 10.00% | |||||
Greater effectiveness, amortization period | 17 years | |||||
Less effectiveness, amortization period | 12 years | |||||
Operating lease, payments | $ 2,500,000,000 | $ 2,400,000,000 | ||||
Weighted average remaining lease term | 5 years 8 months 12 days | 5 years 10 months 24 days | ||||
Weighted average discount rate | 6.20% | 6.20% | ||||
Allowance for credit loss | $ 150,000,000 | |||||
Regulatory assets, probable recovery | 76,000,000 | |||||
Regulatory assets, deferred amount | $ 10,000,000 | |||||
Five Year Historical Period | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Historical data period | 5 years | |||||
Average annual statewide claims or settlements | $ 6,500,000,000 | |||||
Twelve Year Historical Period | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Historical data period | 12 years | |||||
Average annual statewide claims or settlements | $ 2,900,000,000 | |||||
Wildfire Fund Asset | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Finite-lived intangible asset, useful life | 15 years | |||||
Noncurrent liabilities – other | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Wildfire fund, noncurrent | $ 1,300,000,000 | |||||
Pacific Gas & Electric Co (Utility) | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Composite depreciation rate | 3.76% | 3.80% | 3.82% | |||
AFUDC debt recorded | $ 35,000,000 | $ 55,000,000 | $ 53,000,000 | |||
AFUDC equity recorded | 140,000,000 | 79,000,000 | 129,000,000 | |||
Nuclear decommissioning obligation accrued | 5,100,000,000 | 4,900,000,000 | ||||
Estimated cost recovery on spent nuclear fuel storage proceeding every year | 10,600,000,000 | 10,600,000,000 | ||||
Wildfire fund asset | 464,000,000 | 0 | ||||
Amortization and accretion | 413,000,000 | $ 0 | $ 0 | |||
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Aggregate maximum amount of loans made by lenders | 1,000,000,000.0 | $ 1,000,000,000.0 | ||||
Long-term debt, gross | $ 1,000,000,000.0 | |||||
Pacific Gas & Electric Co (Utility) | Diablo Canyon | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Number of generation facilities | numberOfFatality | 2 | |||||
Pacific Gas & Electric Co (Utility) | Humboldt Bay | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Number of generation facilities | numberOfFatality | 1 | |||||
PG&E AR Facility, LLC (SPV) | Receivables Securitization Program | ||||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||||
Accounts receivable, net | $ 2,600,000,000 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Revenue from contracts with customers | |||
Total operating revenues | $ 18,469 | $ 17,129 | $ 16,759 |
Electric | |||
Revenue from contracts with customers | |||
Total operating revenues | 13,858 | 12,740 | 12,713 |
Natural gas | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,611 | 4,389 | 4,046 |
Pacific Gas & Electric Co (Utility) | |||
Revenue from contracts with customers | |||
Total operating revenues | 18,469 | 17,129 | 16,760 |
Pacific Gas & Electric Co (Utility) | Electric | |||
Revenue from contracts with customers | |||
Total operating revenues | 13,185 | 12,437 | |
Regulatory balancing accounts | 673 | 303 | |
Total operating revenues | 13,858 | 12,740 | 12,713 |
Pacific Gas & Electric Co (Utility) | Electric | Residential | |||
Revenue from contracts with customers | |||
Total operating revenues | 5,523 | 4,847 | |
Pacific Gas & Electric Co (Utility) | Electric | Commercial | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,722 | 4,756 | |
Pacific Gas & Electric Co (Utility) | Electric | Industrial | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,530 | 1,493 | |
Pacific Gas & Electric Co (Utility) | Electric | Agricultural | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,471 | 1,106 | |
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting | |||
Revenue from contracts with customers | |||
Total operating revenues | 69 | 67 | |
Pacific Gas & Electric Co (Utility) | Electric | Other | |||
Revenue from contracts with customers | |||
Total operating revenues | (130) | 168 | |
Pacific Gas & Electric Co (Utility) | Natural gas | |||
Revenue from contracts with customers | |||
Total operating revenues | 4,386 | 4,302 | |
Regulatory balancing accounts | 225 | 87 | |
Total operating revenues | 4,611 | 4,389 | $ 4,047 |
Pacific Gas & Electric Co (Utility) | Natural gas | Residential | |||
Revenue from contracts with customers | |||
Total operating revenues | 2,517 | 2,325 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial | |||
Revenue from contracts with customers | |||
Total operating revenues | 597 | 605 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only | |||
Revenue from contracts with customers | |||
Total operating revenues | 1,211 | 1,249 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Other | |||
Revenue from contracts with customers | |||
Total operating revenues | $ 61 | $ 123 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utilities Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 93,892 | $ 88,088 |
Accumulated depreciation | (27,756) | (26,453) |
Net property, plant, and equipment | 66,136 | 61,635 |
Electricity generating facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 13,751 | 13,189 |
Electricity generating facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 5 years | |
Electricity generating facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 75 years | |
Electricity distribution facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 37,675 | 35,237 |
Electricity distribution facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 10 years | |
Electricity distribution facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 70 years | |
Electricity transmission facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 15,556 | 14,281 |
Electricity transmission facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 15 years | |
Electricity transmission facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 75 years | |
Natural gas distribution facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 15,133 | 14,236 |
Natural gas distribution facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 20 years | |
Natural gas distribution facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 60 years | |
Natural gas transmission and storage facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 9,002 | 8,452 |
Natural gas transmission and storage facilities | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 5 years | |
Natural gas transmission and storage facilities | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 66 years | |
Construction work in progress | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 2,757 | 2,675 |
Other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 18 | $ 18 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
ARO liability at beginning of year | $ 5,854 | $ 5,994 |
Liabilities incurred in the current period | 268 | 0 |
Revision in estimated cash flows | 53 | (376) |
Accretion | 265 | 274 |
Liabilities settled | (28) | (38) |
ARO liability at end of year | $ 6,412 | $ 5,854 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Accumulated Other Comprehensive Loss | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | $ (5) | $ (4) |
Net current period other comprehensive loss | (17) | (1) |
Ending balance | (22) | (5) |
Accumulated Other Comprehensive Loss | Pension Plan | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | (22) | (21) |
Net current period other comprehensive loss | (17) | (1) |
Ending balance | (39) | (22) |
Accumulated Other Comprehensive Loss | PBOP Plans | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Beginning balance | 17 | 17 |
Net current period other comprehensive loss | 0 | 0 |
Ending balance | 17 | 17 |
Amortization of prior service cost | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | 6 | 6 |
Amortization of prior service cost | Pension Plan | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | (4) | (4) |
Amounts reclassified from other comprehensive income, tax | 2 | 2 |
Amortization of prior service cost | PBOP Plans | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income: | 10 | 10 |
Amounts reclassified from other comprehensive income, tax | 4 | 4 |
Amortization of net actuarial gain (loss) | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (247) | 288 |
Amounts reclassified from other comprehensive income: | (13) | 0 |
Amortization of net actuarial gain (loss) | Pension Plan | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (417) | 61 |
Amounts reclassified from other comprehensive income: | 2 | 2 |
Other comprehensive income before reclassifications, tax | 162 | 24 |
Amounts reclassified from other comprehensive income, tax | 1 | 1 |
Amortization of net actuarial gain (loss) | PBOP Plans | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 170 | 227 |
Amounts reclassified from other comprehensive income: | (15) | (2) |
Other comprehensive income before reclassifications, tax | 66 | 88 |
Amounts reclassified from other comprehensive income, tax | 6 | 1 |
Regulatory account transfer | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 230 | (289) |
Amounts reclassified from other comprehensive income: | 7 | (6) |
Regulatory account transfer | Pension Plan | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 400 | (62) |
Amounts reclassified from other comprehensive income: | 2 | 2 |
Other comprehensive income before reclassifications, tax | 155 | 24 |
Amounts reclassified from other comprehensive income, tax | 1 | 1 |
Regulatory account transfer | PBOP Plans | ||
AOCI Attributable to Parent, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | (170) | (227) |
Amounts reclassified from other comprehensive income: | 5 | (8) |
Other comprehensive income before reclassifications, tax | 66 | 88 |
Amounts reclassified from other comprehensive income, tax | $ 2 | $ 3 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions |
3 Months Ended | 12 Months Ended |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Accounting Policies [Abstract] | ||
Operating lease fixed cost | $ 679 | $ 686 |
Operating lease variable cost | 1,852 | 1,778 |
Total operating lease cost | $ 2,531 | $ 2,464 |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Future Expected Operating Lease Payments | |
2021 | $ 624 |
2022 | 550 |
2023 | 257 |
2024 | 98 |
2025 | 91 |
Thereafter | 513 |
Total lease payments | 2,133 |
Less imputed interest | (397) |
Total | $ 1,736 |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 8,978 | $ 6,066 |
Utility retained generation asset costs | 1,200 | |
Pension benefits | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,245 | 1,823 |
Environmental compliance costs | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 1,112 | 1,062 |
Recovery Period | 32 years | |
Utility retained generation | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 181 | 228 |
Recovery Period | 6 years | |
Price risk management | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 204 | 124 |
Recovery Period | 19 years | |
Unamortized loss, net of gain, on reacquired debt | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 49 | 63 |
Recovery Period | 23 years | |
Catastrophic event memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 842 | 656 |
Catastrophic event memorandum account | COVID-19 | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 49 | |
Catastrophic event memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Catastrophic event memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
Wildfire expense memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 400 | 423 |
Wildfire expense memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Wildfire expense memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
Fire hazard prevention memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 137 | 259 |
Fire hazard prevention memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Fire hazard prevention memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
Fire risk mitigation memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 66 | 95 |
Fire risk mitigation memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Fire risk mitigation memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
Wildfire mitigation plan memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 390 | 558 |
Wildfire mitigation plan memorandum account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Wildfire mitigation plan memorandum account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
Deferred income tax | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 908 | 252 |
Recovery Period | 51 years | |
Insurance premium costs | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 294 | 0 |
Insurance premium costs | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Insurance premium costs | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 4 years | |
Wildfire mitigation balancing account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 156 | 0 |
Wildfire mitigation balancing account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Cost percentage threshold requiring approval | 115.00% | |
Wildfire mitigation balancing account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
General rate case memorandum accounts | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 376 | 0 |
General rate case memorandum accounts | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
General rate case memorandum accounts | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 2 years | |
Vegetation management balancing account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 592 | 0 |
Vegetation management balancing account | Minimum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 1 year | |
Cost percentage threshold requiring approval | 120.00% | |
Vegetation management balancing account | Maximum | ||
Regulatory Assets [Line Items] | ||
Recovery Period | 3 years | |
COVID-19 Pandemic protection memorandum account | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 84 | 0 |
COVID-19 pandemic protection memorandum account, undercollection bad debt | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 76 | |
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 8 | |
Other | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 942 | $ 523 |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 10,424 | $ 9,270 |
Cost of removal obligations | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 6,905 | 6,456 |
Recoveries in excess of AROs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 458 | 393 |
Public purpose programs | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 948 | 817 |
Retirement Plan | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 995 | 750 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 1,118 | $ 854 |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Regulatory Liabilities [Line Items] | ||
Regulatory balancing accounts | $ 410 | $ 315 |
Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 1,245 | 1,797 |
Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 2,001 | 2,114 |
Electric distribution | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 55 | 31 |
Electric transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 267 | 119 |
Electric transmission | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 0 | 9 |
Gas distribution and transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 76 | 45 |
Gas distribution and transmission | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 102 | 363 |
Energy procurement | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 158 | 649 |
Energy procurement | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 413 | 901 |
Public purpose programs | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 410 | 559 |
Public purpose programs | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 292 | 209 |
Fire hazard prevention memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 121 | 0 |
Fire risk mitigation memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 33 | 0 |
Wildfire mitigation plan memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 161 | 0 |
Wildfire mitigation balancing account | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 27 | 0 |
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 313 | 0 |
Vegetation management balancing account | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 115 | 0 |
Insurance premium costs | ||
Regulatory Liabilities [Line Items] | ||
Regulatory balancing accounts | 93 | |
Insurance premium costs | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 135 | 0 |
Other | Regulatory Balancing Accounts Payable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | 279 | 394 |
Other | Regulatory Balancing Accounts Receivable | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory balancing accounts | $ 289 | $ 632 |
DEBT (Outstanding Borrowings and Availability) (Details) - USD ($) |
Dec. 31, 2020 |
Jul. 01, 2020 |
---|---|---|
Revolving Credit Facility | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 8,000,000,000 | |
Borrowings Outstanding | 4,605,000,000 | |
Letters of Credit Outstanding | 1,020,000,000 | |
Facility Availability | 2,375,000,000 | |
Revolving Credit Facility | PG&E Corporation | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 500,000,000 | $ 500,000,000 |
Borrowings Outstanding | 0 | |
Letters of Credit Outstanding | 0 | |
Facility Availability | 500,000,000 | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 3,500,000,000 | 3,500,000,000 |
Borrowings Outstanding | 605,000,000 | |
Letters of Credit Outstanding | 1,020,000,000 | |
Facility Availability | 1,875,000,000 | |
Letter of credit sublimit | 1,500,000,000 | |
Term Loan | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 3,000,000,000 | |
Borrowings Outstanding | 3,000,000,000 | |
Letters of Credit Outstanding | 0 | |
Facility Availability | 0 | |
Term Loan, June 2021 | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 1,500,000,000 | |
Term Loan, January 2022 | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 | |
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | 1,000,000,000 | |
Borrowings Outstanding | 1,000,000,000.0 | |
Letters of Credit Outstanding | 0 | |
Facility Availability | $ 0 |
DEBT (Credit Facility) (Details) |
Jul. 01, 2020
USD ($)
numberOfExtensionOption
numberOfClaimHolder
|
Dec. 31, 2020
USD ($)
|
---|---|---|
Revolving Credit Facility | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 8,000,000,000 | |
Revolving Credit Facility | PG&E Corporation | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | 500,000,000 |
Debt instrument, term | 3 years | |
Debt, number of extension options | numberOfExtensionOption | 2 | |
Debt instrument, extension option, term | 1 year | |
Percentage of ownership of outstanding common stock | 100.00% | |
Revolving Credit Facility | PG&E Corporation | Minimum | ||
Debt [Line Items] | ||
Facility fee | 0.50% | |
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance | 150.00% | |
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared | 100.00% | |
Revolving Credit Facility | PG&E Corporation | Minimum | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 3.00% | |
Revolving Credit Facility | PG&E Corporation | Minimum | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 2.00% | |
Revolving Credit Facility | PG&E Corporation | Maximum | ||
Debt [Line Items] | ||
Facility fee | 0.75% | |
Debt, ratio of total consolidated debt to consolidated capitalization | 70.00% | |
Debt default, amount | $ 200,000,000 | |
Revolving Credit Facility | PG&E Corporation | Maximum | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 4.25% | |
Revolving Credit Facility | PG&E Corporation | Maximum | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 3.25% | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 3,500,000,000 | $ 3,500,000,000 |
Debt instrument, term | 3 years | |
Debt, number of extension options | numberOfClaimHolder | 2 | |
Debt instrument, extension option, term | 1 year | |
Letter of credit, maximum borrowing capacity | $ 1,500,000,000 | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum | ||
Debt [Line Items] | ||
Facility fee | 0.25% | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 1.375% | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 0.375% | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | ||
Debt [Line Items] | ||
Facility fee | 0.50% | |
Debt, ratio of total consolidated debt to consolidated capitalization | 65.00% | |
Debt default, amount | $ 200,000,000 | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 2.50% | |
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 1.50% | |
Term Loan Credit Facility | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 3,000,000,000.0 | |
Debt, percentage of net cash proceeds from certain securitization transactions prepayment | 100.00% | |
Term Loan Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | ||
Debt [Line Items] | ||
Debt, ratio of total consolidated debt to consolidated capitalization | 65.00% | |
Debt default, amount | $ 200,000,000 | |
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 | |
Debt instrument, term | 364 days | |
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 2.00% | |
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 1.00% | |
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | ||
Debt [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 | |
Debt instrument, term | 18 months | |
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR | ||
Debt [Line Items] | ||
Basis spread on variable rate | 2.25% | |
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate | ||
Debt [Line Items] | ||
Basis spread on variable rate | 1.25% | |
Second Amended and Restated Credit Agreement | PG&E Corporation | ||
Debt [Line Items] | ||
Repayments of debt | $ 300,000,000 |
DEBT (Receivables Securitization Program) (Details) - USD ($) |
Oct. 05, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|---|
Line of Credit Facility [Line Items] | |||
Program termination period | 180 days | ||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | |||
Line of Credit Facility [Line Items] | |||
Percentage pledged of equity interests | 100.00% | ||
Aggregate maximum amount of loans made by lenders | $ 1,000,000,000.0 | $ 1,000,000,000.0 | |
Debt financial instrument | $ 1,000,000,000 | $ 0 |
DEBT (Other Short-term Borrowings and Long-term Debt) (Details) - USD ($) |
Feb. 01, 2021 |
Jul. 01, 2020 |
Jun. 23, 2020 |
Dec. 31, 2020 |
Nov. 16, 2020 |
Jun. 19, 2020 |
---|---|---|---|---|---|---|
PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Debt instrument, redemption price, percentage | 100.00% | |||||
First Mortgage Bonds due November 15, 2021 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,450,000,000 | |||||
Floating Rate First Mortgage Bonds due June 16, 2022 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 500,000,000 | |||||
First Mortgage Bonds due June 16, 2022 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 2,500,000,000 | |||||
Stated interest rate | 1.75% | |||||
First Mortgage Bonds due August 1, 2027 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,000,000,000.0 | |||||
Stated interest rate | 2.10% | |||||
First Mortgage Bonds due February 1, 2031 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 2,000,000,000.0 | |||||
Stated interest rate | 2.50% | |||||
First Mortgage Bonds due August 1, 2040 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,000,000,000.0 | |||||
Stated interest rate | 3.30% | |||||
First Mortgage Bonds due August 1, 2050 | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,925,000,000 | |||||
Stated interest rate | 3.50% | |||||
New Mortgage Bonds | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 11,900,000,000 | |||||
Utility Reinstated Senior Notes | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | 9,600,000,000 | |||||
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 | |||||
Debt instrument, term | 18 months | |||||
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 2.25% | |||||
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 1.25% | |||||
Term Loan | PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 2,750,000,000 | |||||
Debt instrument, quarterly reduction amount | $ 6,875,000 | |||||
Prepayment premium percentage | 1.00% | |||||
Repayments of debt | $ 350,000,000 | |||||
Term Loan | PG&E Corporation | LIBOR | ||||||
Debt [Line Items] | ||||||
Debt instrument, basis spread on alternative base rate | 1.00% | |||||
Term Loan | PG&E Corporation | LIBOR | Subsequent Event | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 3.00% | |||||
Term Loan | PG&E Corporation | Alternative Base Rate (ABR) Floor | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 2.00% | |||||
Term Loan | PG&E Corporation | Prime Rate | ||||||
Debt [Line Items] | ||||||
Debt instrument, basis spread on alternative base rate | 0.50% | |||||
Term Loan | PG&E Corporation | Alternative Base Rate (ABR) | Subsequent Event | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 2.00% | |||||
Term Loan | PG&E Corporation | Minimum | LIBOR | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 1.00% | |||||
Term Loan | PG&E Corporation | Maximum | ||||||
Debt [Line Items] | ||||||
Debt default, amount | $ 200,000,000 | |||||
Term Loan | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 3,000,000,000 | |||||
Percentage of ownership of outstanding common stock | 100.00% | |||||
Term Loan, Repricing Amendment | PG&E Corporation | LIBOR | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 4.50% | |||||
Term Loan, Repricing Amendment | PG&E Corporation | Alternative Base Rate (ABR) Floor | Subsequent Event | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 1.50% | |||||
Term Loan, Repricing Amendment | PG&E Corporation | Alternative Base Rate (ABR) | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 3.50% | |||||
Term Loan, Repricing Amendment | PG&E Corporation | Minimum | LIBOR | Subsequent Event | ||||||
Debt [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
Senior Secured Notes due July 1, 2028 | PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,000,000,000.0 | |||||
Stated interest rate | 5.00% | |||||
Senior Secured Notes due July 1, 2030 | PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Debt instrument, face amount | $ 1,000,000,000.0 | |||||
Stated interest rate | 5.25% | |||||
Senior Notes | PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Debt instrument, redemption price, percentage | 40.00% |
DEBT (Schedule of Long-term Debt) (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Jul. 01, 2020 |
Dec. 31, 2019 |
|
Pre-petition Long Term Debt | PG&E Corporation | |||
Debt [Line Items] | |||
Senior notes | $ 0 | $ 650,000,000 | |
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation | |||
Debt [Line Items] | |||
Total Pre-Petition Pollution Control Bonds | 0 | $ 300,000,000 | |
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 3.24% | ||
Term Loan - Stated Maturity: 2020 | PG&E Corporation | |||
Debt [Line Items] | |||
Debt | 0 | $ 350,000,000 | |
Term Loan - Stated Maturity: 2020 | PG&E Corporation | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 2.96% | ||
Pre-petition Senior Notes | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | 0 | $ 17,525,000,000 | |
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 1,750,000,000 | |
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 2.45% | ||
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.25% | ||
First Mortgage Bonds Due 2025 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.45% | ||
Debt instrument, face amount | $ 875,000,000 | ||
First Mortgage Bonds Due 2025 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 3.45% | ||
First Mortgage Bonds Due 2028 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.75% | ||
Debt instrument, face amount | $ 875,000,000 | ||
First Mortgage Bonds Due 2028 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 3.75% | ||
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 5,025,000,000 | |
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 2.95% | ||
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.65% | ||
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 5,700,000,000 | |
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 5.40% | ||
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 6.35% | ||
First Mortgage Bonds Due 2030 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.55% | ||
Debt instrument, face amount | $ 3,100,000,000 | ||
First Mortgage Bonds Due 2030 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 4.55% | ||
First Mortgage Bonds Due 2050 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.95% | ||
Debt instrument, face amount | $ 3,100,000,000 | ||
First Mortgage Bonds Due 2050 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 4.95% | ||
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 1,000,000,000 | |
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 3.75% | ||
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.50% | ||
Senior Notes Due 2043 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 500,000,000 | |
Stated interest rate | 5.13% | ||
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | $ 0 | 3,550,000,000 | |
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 3.95% | ||
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.75% | ||
Pre-petition Pollution Control Bonds | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
PG&E Corporation | $ 0 | 863,000,000 | |
Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 0.0175% | ||
Pollution control bonds | $ 0 | $ 100,000,000 | $ 100,000,000 |
Pollution Control Bonds Series 2009, A-B, Variable Rate, Due 2026 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 7.95% | ||
Pollution control bonds | 0 | $ 149,000,000 | |
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Pollution control bonds | 0 | $ 614,000,000 | |
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 7.95% | ||
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 8.08% | ||
Pre-Petition Credit Facility | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Senior notes | 0 | $ 3,138,000,000 | |
Utility Revolving Credit Facilities - Stated Maturity: 2022 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Total Pre-Petition Pollution Control Bonds | 0 | $ 2,888,000,000 | |
Utility Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 3.04% | ||
Term Loan - Stated Maturity: 2019 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Debt | 0 | $ 250,000,000 | |
Term Loan - Stated Maturity: 2019 | PG&E Corporation | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 2.36% | ||
First Mortgage Bonds Due 2026 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.15% | ||
Debt instrument, face amount | $ 1,950,000,000 | ||
First Mortgage Bonds Due 2040 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.50% | ||
Debt instrument, face amount | $ 1,950,000,000 | ||
Pre-Petition Debt | |||
Debt [Line Items] | |||
Long-term debt | 0 | $ 22,176,000,000 | |
Pre-Petition Debt | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | 0 | 21,526,000,000 | |
Debt instrument, face amount | 17,900,000,000 | ||
New Debt | |||
Debt [Line Items] | |||
Long-term debt | 37,288,000,000 | 0 | |
New Debt | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | 32,664,000,000 | 0 | |
Unamortized discount, net of premium and debt issuance costs | (6,000,000) | 0 | |
New Debt | PG&E Corporation | |||
Debt [Line Items] | |||
Long-term debt | 4,624,000,000 | 0 | |
Unamortized discount, net of premium and debt issuance costs | (85,000,000) | 0 | |
Term Loan, Stated Maturity 2025 | PG&E Corporation | |||
Debt [Line Items] | |||
Long-term debt, gross | $ 2,709,000,000 | 0 | |
Term Loan, Stated Maturity 2025 | PG&E Corporation | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 5.50% | ||
Senior Notes Due 2028 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 5.00% | ||
Long-term debt, gross | $ 1,000,000,000 | 0 | |
Senior Notes Due 2030 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 5.25% | ||
Long-term debt, gross | $ 1,000,000,000 | 0 | |
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Debt | $ 1,500,000,000 | 0 | |
Debt Instrument, term | 18 months | ||
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 2.44% | ||
First Mortgage Bonds, Reinstated | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | $ 9,575,000,000 | 0 | |
Unamortized discount, net of premium and debt issuance costs | 0 | 0 | |
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt, gross | $ 5,025,000,000 | 0 | |
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 2.95% | ||
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.65% | ||
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt, gross | $ 1,000,000,000 | 0 | |
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 3.75% | ||
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.50% | ||
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt, gross | $ 3,550,000,000 | 0 | |
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility) | Minimum | |||
Debt [Line Items] | |||
Stated interest rate | 3.95% | ||
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility) | Maximum | |||
Debt [Line Items] | |||
Stated interest rate | 4.75% | ||
First Mortgage Bonds, Exchange | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | $ 11,754,000,000 | 0 | |
Unamortized discount, net of premium and debt issuance costs | $ (98,000,000) | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.45% | ||
Long-term debt, gross | $ 875,000,000 | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2025 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 3.15% | ||
First Mortgage Bonds, Exchange Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.15% | ||
Long-term debt, gross | $ 1,951,000,000 | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.75% | ||
Long-term debt, gross | $ 875,000,000 | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2030 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.55% | ||
Long-term debt, gross | $ 3,100,000,000 | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.50% | ||
Long-term debt, gross | $ 1,951,000,000 | 0 | |
First Mortgage Bonds, Exchange Stated Maturity 2040 | PG&E Corporation | |||
Debt [Line Items] | |||
Stated interest rate | 4.50% | ||
First Mortgage Bonds, Exchange Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 4.95% | ||
Long-term debt, gross | $ 3,100,000,000 | 0 | |
First Mortgage Bonds | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | 8,841,000,000 | 0 | |
Unamortized discount, net of premium and debt issuance costs | (84,000,000) | 0 | |
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt, gross | $ 500,000,000 | 0 | |
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | LIBOR | |||
Debt [Line Items] | |||
Stated interest rate | 1.70% | ||
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 1.75% | ||
Long-term debt, gross | $ 2,500,000,000 | 0 | |
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 2.10% | ||
Long-term debt, gross | $ 1,000,000,000 | 0 | |
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 2.50% | ||
Long-term debt, gross | $ 2,000,000,000 | 0 | |
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.30% | ||
Long-term debt, gross | $ 1,000,000,000 | 0 | |
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Stated interest rate | 3.50% | ||
Long-term debt, gross | $ 1,925,000,000 | 0 | |
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | |||
Debt [Line Items] | |||
Long-term debt | 1,000,000,000 | $ 0 | |
Long-term debt, gross | $ 1,000,000,000.0 |
DEBT (Schedule of Contractual Repayment Schedule) (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2020
USD ($)
| |
Debt [Line Items] | |
Total consolidated debt | $ 37,589 |
Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.66% |
Fixed rate obligations | $ 29,852 |
Variable rate obligations | $ 3,000 |
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan | |
Debt [Line Items] | |
Debt Instrument, term | 18 months |
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan | LIBOR | |
Debt [Line Items] | |
Debt, average interest rate | 2.44% |
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program | LIBOR | |
Debt [Line Items] | |
Debt, average interest rate | 1.57% |
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Stated Maturity 2022 | LIBOR | |
Debt [Line Items] | |
Debt, average interest rate | 1.70% |
PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 5.13% |
Fixed rate obligations | $ 2,000 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 2,737 |
2021 | |
Debt [Line Items] | |
Total consolidated debt | $ 28 |
2021 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
2021 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 28 |
2022 | |
Debt [Line Items] | |
Total consolidated debt | $ 5,528 |
2022 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 1.75% |
Fixed rate obligations | $ 2,500 |
Variable rate obligations | $ 3,000 |
2022 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 28 |
2023 | |
Debt [Line Items] | |
Total consolidated debt | $ 1,203 |
2023 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.83% |
Fixed rate obligations | $ 1,175 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
2023 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 28 |
2024 | |
Debt [Line Items] | |
Total consolidated debt | $ 828 |
2024 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.60% |
Fixed rate obligations | $ 800 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
2024 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 28 |
2025 | |
Debt [Line Items] | |
Total consolidated debt | $ 4,100 |
2025 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.47% |
Fixed rate obligations | $ 1,475 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
2025 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0.00% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2020 | 5.50% |
Variable rate obligations | $ 2,625 |
Thereafter | |
Debt [Line Items] | |
Total consolidated debt | $ 25,902 |
Thereafter | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.87% |
Fixed rate obligations | $ 23,902 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
Thereafter | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 5.13% |
Fixed rate obligations | $ 2,000 |
Variable interest rate as of December 31, 2020 | 0.00% |
Variable rate obligations | $ 0 |
COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) $ / shares in Units, purchaseContract in Thousands, equityUnit in Thousands |
1 Months Ended | 3 Months Ended | 12 Months Ended | 72 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Aug. 03, 2020
USD ($)
equityUnit
shares
|
Jul. 01, 2020
USD ($)
shares
|
Jun. 25, 2020
USD ($)
equityUnit
purchaseContract
shares
|
Jun. 07, 2020
USD ($)
$ / shares
|
May 28, 2020 |
Jul. 31, 2020
USD ($)
|
Jun. 30, 2020
USD ($)
|
Dec. 31, 2020
USD ($)
$ / shares
shares
|
Dec. 31, 2019
USD ($)
$ / shares
shares
|
Dec. 31, 2018
USD ($)
$ / shares
|
Dec. 31, 2020
USD ($)
shares
|
Jun. 22, 2020
shares
|
Mar. 20, 2020
USD ($)
|
|
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Common stock, shares outstanding (in shares) | 1,984,678,673 | 529,236,741 | 1,984,678,673 | ||||||||||
Common stock, shares authorized (in shares) | 3,600,000,000 | 800,000,000 | 3,600,000,000 | 3,600,000,000 | |||||||||
Preferred stock, shares authorized (in shares) | 400,000,000 | ||||||||||||
Equity Units issued | $ | $ 9,000,000,000.0 | $ 3,970,000,000 | $ 9,000,000,000.0 | $ 1,304,000,000 | $ 0 | $ 0 | |||||||
Sale of stock, consideration received on transaction | $ | $ 3,250,000,000 | ||||||||||||
Sale of stock, price per share (in dollars per share) | $ / shares | $ 9.50 | ||||||||||||
Sale of stock, number of shares issued in transaction (in shares) | 342,100,000 | ||||||||||||
Proceeds from issuance or sale of equity, net | $ | $ 5,200,000,000 | $ 1,190,000,000 | |||||||||||
Proceeds from equity backstop commitments and forward stock purchase agreements | $ | 523,000,000 | ||||||||||||
Sale of stock, redemption of rights, return amount | $ | $ 120,500,000 | ||||||||||||
Sale of stock, issuance and delivery, common stock (in shares) | 42,300,000 | ||||||||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000.0 | ||||||||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | ||||||||||||
Equity contribution cash | $ | $ 12,900,000,000 | $ 12,900,000,000 | |||||||||||
Percentage of equity security ownership with board of director approval | 4.75% | 4.75% | |||||||||||
Deferred tax asset, litigation adjustment | $ | $ 619,000,000 | ||||||||||||
Dividend reinstatement target, amount | $ | $ 6,200,000,000 | ||||||||||||
Equity capital structure percentage | 52.00% | ||||||||||||
Equity capital structure, waiver period | 5 years | ||||||||||||
Number of shares issued for LTIP, maximum (in shares) | 17,000,000 | 17,000,000 | |||||||||||
Shares available for LTIP award (in shares) | 29,174,205 | 29,174,205 | |||||||||||
Weighted average grant date fair value of granted shares (in dollars per share) | $ / shares | $ 9.25 | $ 18.57 | $ 40.92 | ||||||||||
Total fair value | $ | $ 31,000,000 | $ 42,000,000 | $ 41,000,000 | ||||||||||
Total unrecognized compensation costs | $ | $ 6,000,000 | ||||||||||||
Remaining weighted average period | 1 year 6 months 29 days | ||||||||||||
Fire Trust Victim | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000 | ||||||||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | ||||||||||||
Litigation liability, payment accrual | $ | $ 6,750,000,000 | ||||||||||||
Transfer of shares related to litigation settlement, value | $ | 4,530,000,000 | ||||||||||||
Difference between payment accrual and transfer of shares related to litigation settlement, value | $ | $ 2,200,000,000 | ||||||||||||
Minimum | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of equity units, right to receive | 125,000,000 | ||||||||||||
Sale of stock, number of additional units, right to receive (in shares) | 12,500,000 | ||||||||||||
Maximum | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of equity units, right to receive | 153,000,000 | ||||||||||||
Sale of stock, number of additional units, right to receive (in shares) | 15,300,000 | ||||||||||||
2014 LTIP, Amended | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Number of shares issued for LTIP, maximum (in shares) | 47,000,000 | 47,000,000 | |||||||||||
Stock Options | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Granted (in shares) | 0 | ||||||||||||
Tax benefit from share based awards | $ | $ 0 | ||||||||||||
Weighted-average period | 2 years 2 months 12 days | ||||||||||||
Stock Options | 2014 LTIP | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Term of award | 10 years | ||||||||||||
Award vesting period | 3 years | ||||||||||||
Total unrecognized compensation costs | $ | $ 500,000 | $ 500,000 | |||||||||||
Weighted average grant date fair value of granted shares (in dollars per share) | $ / shares | $ 3.87 | ||||||||||||
Granted (in shares) | 20,065 | ||||||||||||
Restricted stock units | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Award vesting period | 3 years | ||||||||||||
Tax detriment | $ | $ 19,000,000 | ||||||||||||
Performance shares | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Award vesting period | 3 years | ||||||||||||
Tax detriment | $ | $ 49,000,000 | ||||||||||||
Industry performance period | 3 years | ||||||||||||
Award grant date fair value recognition period | 3 years | ||||||||||||
Performance shares granted (in dollars per share) | $ / shares | $ 9.62 | $ 15.39 | $ 36.92 | ||||||||||
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $ | $ 54,000,000 | ||||||||||||
Common Stock Offering | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of shares issued in transaction (in shares) | 423,400,000 | ||||||||||||
Option to purchase additional stock (in shares) | 42,300,000 | 42,300,000 | |||||||||||
Equity Units Offering | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of equity units issued in transaction (in equity units) | equityUnit | 14,500 | ||||||||||||
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction (in purchase contracts) | purchaseContract | 14,500 | ||||||||||||
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction, additional contracts (in purchase contracts) | purchaseContract | 1,450 | ||||||||||||
Option to purchase additional contracts (in equity units) | equityUnit | 1,450 | ||||||||||||
Sale of stock, number of equity units issued and sold in transaction, additional (in equity units) | equityUnit | 1,450 | ||||||||||||
Common Stock Underwriters | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of shares issued and sold in transaction (in shares) | 423,400,000 | ||||||||||||
Equity Units Underwriters | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction (in purchase contracts) | purchaseContract | 14,500 | ||||||||||||
PG&E Corporation | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Preferred stock, shares authorized (in shares) | 400,000,000 | 400,000,000 | |||||||||||
Equity Units issued | $ | $ 1,304,000,000 | $ 0 | $ 0 | ||||||||||
unrecognized compensation cost, period | 1 month 28 days | ||||||||||||
PG&E Corporation | Minimum | Revolving Credit Facility | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance | 150.00% | ||||||||||||
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared | 100.00% | ||||||||||||
PG&E Corporation | Maximum | Revolving Credit Facility | |||||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||||
Debt, ratio of total consolidated debt to consolidated capitalization | 70.00% |
COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 35 | $ 50 | $ 89 |
Total compensation expense (after-tax) | 25 | 35 | 63 |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 3 | 7 | 10 |
Restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 15 | 21 | 43 |
Performance shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 17 | $ 22 | $ 36 |
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Significant Assumptions Used for Shares Granted) (Details) - 2014 LTIP - Stock Options |
12 Months Ended |
---|---|
Dec. 31, 2019 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Expected stock price volatility | 57.00% |
Expected annual dividend payment | 0.00% |
Expected life (years) | 4 years 6 months |
Minimum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 1.51% |
Maximum | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Risk-free interest rate | 1.52% |
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Stock Options |
12 Months Ended |
---|---|
Dec. 31, 2020
$ / shares
shares
| |
Number of Stock Options | |
Granted (in shares) | 0 |
2014 LTIP | |
Number of Stock Options | |
Outstanding, beginning of period (in shares) | 4,281,403 |
Granted (in shares) | 20,065 |
Exercised (in shares) | 0 |
Forfeited or expired (in shares) | (2,080,221) |
Outstanding, end of period (in shares) | 2,221,247 |
Vested or expected to vest (in shares) | 2,215,076 |
Exercisable (in shares) | 1,840,893 |
Weighted Average Grant- Date Fair Value | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 5.98 |
Granted (in dollars per share) | $ / shares | 3.87 |
Forfeited or expired (in dollars per share) | $ / shares | 3.87 |
Outstanding, end of period (in dollars per share) | $ / shares | 7.45 |
Vested or expected to vest (in dollars per share) | $ / shares | 7.43 |
Exercisable (in dollars per share) | $ / shares | $ 6.86 |
Weighted Average Remaining Contractual Term | |
Outstanding | 5 years 3 months 29 days |
Expected to vest | 5 years 3 months 21 days |
Exercisable | 4 years 11 months 4 days |
COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Number of Restricted Stock Units | |||
Nonvested, beginning balance (in shares) | 1,040,835 | ||
Granted (in shares) | 1,007,782 | ||
Vested (in shares) | (944,090) | ||
Forfeited (in shares) | (214,174) | ||
Nonvested, ending balance (in shares) | 890,353 | 1,040,835 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested, beginning balance (in dollars per share) | $ 44.06 | ||
Granted (in dollars per share) | 9.25 | $ 18.57 | $ 40.92 |
Vested (in dollars per share) | 33.14 | ||
Forfeited (in dollars per share) | 15.75 | ||
Nonvested, ending balance (in dollars per share) | $ 23.05 | $ 44.06 |
COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Number of Performance Shares | |||
Nonvested , beginning balance (in shares) | 688,423 | ||
Granted (in shares) | 7,951,541 | ||
Vested (in shares) | (132,526) | ||
Forfeited (in shares) | (1,218,656) | ||
Nonvested, ending balance (in shares) | 7,288,782 | 688,423 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested, beginning balance (in dollars per share) | $ 36.92 | ||
Granted (in dollars per share) | 9.62 | $ 15.39 | $ 36.92 |
Vested (in dollars per share) | 41.27 | ||
Forfeited (in dollars per share) | 24.38 | ||
Nonvested, ending balance (in dollars per share) | 9.16 | $ 36.92 | |
Expirations, fair value (in dollars per share) | $ 0 |
PREFERRED STOCK (Narrative) (Details) - USD ($) |
12 Months Ended | |||
---|---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
Jun. 22, 2020 |
|
Preferred Stock [Line Items] | ||||
Preferred stock, shares authorized (in shares) | 400,000,000 | |||
Pacific Gas & Electric Co (Utility) | ||||
Preferred Stock [Line Items] | ||||
Preferred stock dividend | $ 0 | $ 0 | $ 0 | |
Pacific Gas & Electric Co (Utility) | Minimum | ||||
Preferred Stock [Line Items] | ||||
Redemption price (in dollars per share) | $ 25.75 | $ 25.75 | ||
Pacific Gas & Electric Co (Utility) | Maximum | ||||
Preferred Stock [Line Items] | ||||
Redemption price (in dollars per share) | $ 27.25 | $ 27.25 | ||
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | ||||
Preferred Stock [Line Items] | ||||
Nonredeemable preferred stock outstanding | $ 145,000,000 | $ 145,000,000 | ||
Preferred stock dividends per share, low range (in dollars per share) | $ 1.25 | |||
Preferred stock dividends per share, high range (in dollars per share) | $ 1.50 | |||
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Minimum | ||||
Preferred Stock [Line Items] | ||||
Preferred stock interest rate | 5.00% | 5.00% | ||
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum | ||||
Preferred Stock [Line Items] | ||||
Preferred stock interest rate | 6.00% | 6.00% | ||
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | ||||
Preferred Stock [Line Items] | ||||
Redeemable preferred stock outstanding | $ 113,000,000 | $ 113,000,000 | ||
Preferred stock dividends per share, low range (in dollars per share) | $ 1.09 | |||
Preferred stock dividends per share, high range (in dollars per share) | $ 1.25 | |||
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Minimum | ||||
Preferred Stock [Line Items] | ||||
Preferred stock interest rate | 4.36% | 4.36% | ||
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Maximum | ||||
Preferred Stock [Line Items] | ||||
Preferred stock interest rate | 5.00% | 5.00% | ||
PG&E Corporation | ||||
Preferred Stock [Line Items] | ||||
Preferred stock, shares authorized (in shares) | 400,000,000 | |||
Preferred stock, shares outstanding (in shares) | 0 | |||
$100 Par Value | Pacific Gas & Electric Co (Utility) | ||||
Preferred Stock [Line Items] | ||||
Preferred stock, shares authorized (in shares) | 10,000,000 | |||
Preferred stock, shares outstanding (in shares) | 0 | |||
Preferred stock, par value (in dollars per share) | $ 100 | |||
$25 Par Value | Pacific Gas & Electric Co (Utility) | ||||
Preferred Stock [Line Items] | ||||
Preferred stock, shares authorized (in shares) | 75,000,000 | |||
Preferred stock, par value (in dollars per share) | $ 25 |
EARNINGS PER SHARE (Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Shares of Common Stock Outstanding for Calculating Diluted EPS) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Earnings Per Share [Abstract] | |||
Loss attributable to common shareholders | $ (1,318) | $ (7,656) | $ (6,851) |
Weighted average common shares outstanding, basic (in shares) | 1,257 | 528 | 517 |
Add incremental shares from assumed conversions: | |||
Employee share-based compensation (in shares) | 0 | 0 | 0 |
Equity Units (in shares) | 0 | 0 | 0 |
Weighted average common share outstanding, diluted (in shares) | 1,257 | 528 | 517 |
Total Loss per common share, diluted (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Current: | |||
Federal | $ (26) | $ 1 | $ (5) |
State | (34) | 101 | (8) |
Deferred: | |||
Federal | 258 | (2,361) | (2,264) |
State | 171 | (1,136) | (1,009) |
Tax credits | (7) | (5) | (6) |
Income tax provision (benefit) | 362 | (3,400) | (3,292) |
Pacific Gas & Electric Co (Utility) | |||
Current: | |||
Federal | (26) | 4 | 5 |
State | (34) | 94 | (7) |
Deferred: | |||
Federal | 290 | (2,363) | (2,278) |
State | 185 | (1,137) | (1,009) |
Tax credits | (7) | (5) | (6) |
Income tax provision (benefit) | $ 408 | $ (3,407) | $ (3,295) |
INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Pacific Gas & Electric Co (Utility) | ||
Deferred income tax assets: | ||
Tax carryforwards | $ 7,529 | $ 1,308 |
Compensation | 109 | 92 |
Wildfire-related claims | 544 | 6,520 |
Operating lease liability | 488 | 640 |
Other | 219 | 121 |
Total deferred income tax assets | 8,889 | 8,681 |
Deferred income tax liabilities: | ||
Property related basis differences | 8,300 | 7,973 |
Regulatory balancing accounts | 763 | 381 |
Debt financing costs | 526 | 0 |
Operating lease right of use asset | 488 | 640 |
Income tax regulatory asset | 254 | 71 |
Other | 128 | 58 |
Total deferred income tax liabilities | 10,459 | 9,123 |
Total net deferred income tax liabilities | 1,570 | 442 |
PG&E Corporation | ||
Deferred income tax assets: | ||
Tax carryforwards | 7,641 | 1,390 |
Compensation | 187 | 151 |
Wildfire-related claims | 544 | 6,520 |
Operating lease liability | 489 | 642 |
Other | 212 | 112 |
Total deferred income tax assets | 9,073 | 8,815 |
Deferred income tax liabilities: | ||
Property related basis differences | 8,311 | 7,984 |
Regulatory balancing accounts | 763 | 381 |
Debt financing costs | 526 | 0 |
Operating lease right of use asset | 489 | 642 |
Income tax regulatory asset | 254 | 71 |
Other | 128 | 57 |
Total deferred income tax liabilities | 10,471 | 9,135 |
Total net deferred income tax liabilities | $ 1,398 | $ 320 |
INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Pacific Gas & Electric Co (Utility) | |||
Federal statutory income tax rate | 21.00% | 21.00% | 21.00% |
State income tax (net of federal benefit) | 19.10% | 7.50% | 7.90% |
Effect of regulatory treatment of fixed asset differences | (44.90%) | 2.80% | 3.60% |
Tax credits | (1.70%) | 0.10% | 0.10% |
Bankruptcy and emergence | 54.10% | 0.00% | 0.00% |
Other, net | 2.20% | (0.50%) | 0.00% |
Effective tax rate | 49.80% | 30.90% | 32.60% |
PG&E Corporation | |||
Federal statutory income tax rate | 21.00% | 21.00% | 21.00% |
State income tax (net of federal benefit) | (15.30%) | 7.50% | 7.90% |
Effect of regulatory treatment of fixed asset differences | 39.00% | 2.80% | 3.60% |
Tax credits | 1.50% | 0.10% | 0.10% |
Bankruptcy and emergence | (82.50%) | 0.00% | 0.00% |
Other, net | (2.10%) | (0.60%) | (0.10%) |
Effective tax rate | (38.40%) | 30.80% | 32.50% |
INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Pacific Gas & Electric Co (Utility) | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | $ 420 | $ 377 | $ 349 |
Reductions for tax position taken during a prior year | (43) | (1) | (27) |
Additions for tax position taken during the current year | 60 | 44 | 55 |
Settlements | 0 | 0 | 0 |
Expiration of statute | 0 | 0 | 0 |
Balance, end of period | 437 | 420 | 377 |
PG&E Corporation | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | 420 | 377 | 349 |
Reductions for tax position taken during a prior year | (43) | (1) | (27) |
Additions for tax position taken during the current year | 60 | 44 | 55 |
Settlements | 0 | 0 | 0 |
Expiration of statute | 0 | 0 | 0 |
Balance, end of period | $ 437 | $ 420 | $ 377 |
INCOME TAXES (Narrative) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Income Tax Disclosure [Abstract] | |
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year | $ 16 |
INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Federal | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward | $ 134 |
Federal | Pre-2018 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 3,600 |
Federal | Post-2017 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 24,887 |
State | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 25,364 |
Tax credit carryforward | $ 100 |
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details) |
Dec. 31, 2020
MWh
MMBTU
|
Dec. 31, 2019
MMBTU
MWh
|
---|---|---|
Forwards, Futures and Swaps | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | 146,642,863 | 131,896,159 |
Forwards, Futures and Swaps | Electricity (Megawatt-hours) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 9,435,830 | 18,675,852 |
Options | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | 14,140,000 | 14,720,000 |
Options | Electricity (Megawatt-hours) | ||
Derivative [Line Items] | ||
Contract Volume | 0 | 0 |
Congestion revenue rights | Electricity (Megawatt-hours) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 266,091,470 | 308,467,999 |
DERIVATIVES (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 8 | |
Netting | $ (115) | |
Netting | 25 | 14 |
Commodity Contract | Pacific Gas & Electric Co (Utility) | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (73) | 5 |
Netting | 0 | 0 |
Cash Collateral | 140 | 6 |
Total Derivative Balance | 67 | 11 |
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 33 | 36 |
Netting | 0 | (6) |
Cash Collateral | 115 | 4 |
Total Derivative Balance | 148 | 34 |
Commodity Contract | Pacific Gas & Electric Co (Utility) | Other noncurrent assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 136 | 130 |
Netting | 0 | (6) |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 136 | 124 |
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (38) | (31) |
Netting | 0 | 6 |
Cash Collateral | 15 | 2 |
Total Derivative Balance | (23) | (23) |
Commodity Contract | Pacific Gas & Electric Co (Utility) | Noncurrent liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (204) | (130) |
Netting | 0 | 6 |
Cash Collateral | 10 | 0 |
Total Derivative Balance | $ (194) | $ (124) |
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | $ 470 | $ 1,323 |
Total nuclear decommissioning trusts | 4,209 | 3,703 |
Rabbi trusts | 185 | 173 |
Long-term disability trust | 167 | 166 |
Netting | (8) | |
Netting | (115) | |
Total assets | 5,315 | 5,523 |
Netting | (25) | (14) |
Amount primarily related to deferred taxes on appreciation of investment value | 671 | 530 |
Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting | (11) | |
Netting | (2) | |
Netting | (25) | (13) |
Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Netting | (113) | (3) |
Netting | 0 | (1) |
Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 27 | 6 |
Long-term disability trust | 9 | 10 |
Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 2,398 | 2,086 |
Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 1,759 | 1,590 |
Rabbi trusts | 106 | 100 |
Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 284 | 158 |
TOTAL LIABILITIES | 217 | 147 |
Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 170 | 152 |
TOTAL LIABILITIES | 214 | 146 |
Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 114 | 6 |
TOTAL LIABILITIES | 3 | 1 |
Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 79 | 73 |
Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 470 | 1,323 |
Total nuclear decommissioning trusts | 3,349 | 2,954 |
Rabbi trusts | 0 | 0 |
Long-term disability trust | 9 | 10 |
Total assets | 3,828 | 4,287 |
Level 1 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 27 | 6 |
Long-term disability trust | 9 | 10 |
Level 1 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 2,398 | 2,086 |
Level 1 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 924 | 862 |
Rabbi trusts | 0 | 0 |
Level 1 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 1 |
Level 1 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 1 |
Level 1 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 0 |
Level 1 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 0 | 0 |
Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 0 | 0 |
Total nuclear decommissioning trusts | 835 | 728 |
Rabbi trusts | 185 | 173 |
Long-term disability trust | 0 | 0 |
Total assets | 1,023 | 906 |
Level 2 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Level 2 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Level 2 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 835 | 728 |
Rabbi trusts | 106 | 100 |
Level 2 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 3 | 5 |
TOTAL LIABILITIES | 4 | 4 |
Level 2 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 2 | 2 |
TOTAL LIABILITIES | 1 | 2 |
Level 2 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 1 | 3 |
TOTAL LIABILITIES | 3 | 2 |
Level 2 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 79 | 73 |
Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Short-term investments | 0 | 0 |
Total nuclear decommissioning trusts | 0 | 0 |
Rabbi trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Total assets | 166 | 161 |
Level 3 | Short-term investments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Long-term disability trust | 0 | 0 |
Level 3 | Global equity securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Level 3 | Fixed-income securities | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 0 | 0 |
Rabbi trusts | 0 | 0 |
Level 3 | Price risk management instruments | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 166 | 161 |
TOTAL LIABILITIES | 238 | 156 |
Level 3 | Price risk management instruments | Electric | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 166 | 161 |
TOTAL LIABILITIES | 238 | 156 |
Level 3 | Price risk management instruments | Gas | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total price risk management instruments | 0 | 0 |
TOTAL LIABILITIES | 0 | 0 |
Level 3 | Life insurance contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Rabbi trusts | 0 | 0 |
Assets measured at NAV | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total nuclear decommissioning trusts | 25 | 21 |
Long-term disability trust | $ 158 | $ 156 |
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
$ / shares
|
Dec. 31, 2019
USD ($)
$ / shares
|
---|---|---|
Market approach | Congestion revenue rights | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | $ 153 | $ 140 |
Liabilities | $ | 74 | 44 |
Discounted cash flow | Power purchase agreements | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | 13 | 21 |
Liabilities | $ | $ 164 | $ 112 |
CRR auction prices | Market approach | Congestion revenue rights | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | (320.25) | (20.20) |
CRR auction prices | Market approach | Congestion revenue rights | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 320.25 | 20.20 |
CRR auction prices | Market approach | Congestion revenue rights | Weighted average price | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 0.30 | 0.28 |
Forward prices | Discounted cash flow | Power purchase agreements | Minimum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 12.56 | 11.77 |
Forward prices | Discounted cash flow | Power purchase agreements | Maximum | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 148.30 | 59.38 |
Forward prices | Discounted cash flow | Power purchase agreements | Weighted average price | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Range (in dollars per mwh) | 35.52 | 33.62 |
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Asset (liability) balance, beginning of period | $ 5 | $ 95 |
Included in regulatory assets and liabilities or balancing accounts | (77) | (90) |
Asset (liability) balance, end of period | $ (72) | $ 5 |
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Pacific Gas & Electric Co (Utility) | Pre-Petition Debt | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt instrument, face amount | $ 17,900 | |
Carrying Amount | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | $ 1,901 | 0 |
Carrying Amount | Pacific Gas & Electric Co (Utility) | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 29,664 | 1,500 |
Level 2 | Estimate of Fair Value Measurement | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 2,175 | 0 |
Level 2 | Estimate of Fair Value Measurement | Pacific Gas & Electric Co (Utility) | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | $ 32,632 | $ 1,500 |
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | $ 2,180 | $ 2,011 |
Total Unrealized Gains | 2,033 | 1,698 |
Total Unrealized Losses | (4) | (6) |
Total Fair Value | 4,209 | 3,703 |
Amount primarily related to deferred taxes on appreciation of investment value | 671 | 530 |
Short-term investments | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 27 | 6 |
Total Unrealized Gains | 0 | 0 |
Total Unrealized Losses | 0 | 0 |
Total Fair Value | 27 | 6 |
Global equity securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 543 | 500 |
Total Unrealized Gains | 1,881 | 1,609 |
Total Unrealized Losses | (1) | (2) |
Total Fair Value | 2,423 | 2,107 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 1,610 | 1,505 |
Total Unrealized Gains | 152 | 89 |
Total Unrealized Losses | (3) | (4) |
Total Fair Value | $ 1,759 | $ 1,590 |
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Debt Securities, Available-for-sale [Line Items] | ||
Total maturities of fixed-income securities | $ 4,209 | $ 3,703 |
Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Less than 1 year | 50 | |
1–5 years | 475 | |
5–10 years | 403 | |
More than 10 years | 831 | |
Total maturities of fixed-income securities | $ 1,759 | $ 1,590 |
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Fair Value Disclosures [Abstract] | |||
Proceeds from sales and maturities of nuclear decommissioning investments | $ 1,518 | $ 956 | $ 1,412 |
Gross realized gains on securities | 159 | 69 | 54 |
Gross realized losses on securities | $ (41) | $ (14) | $ (24) |
EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020
USD ($)
noncallable_bond
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
|
Defined Benefit Plan Disclosure [Line Items] | |||
Assumed health care cost trend rate | 6.30% | ||
Ultimate trend rate | 4.50% | ||
Assumed return | 5.10% | ||
10 year actual rate of return | 9.60% | ||
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond | 835 | ||
Total fair value of trust other net liabilities | $ (249) | $ 99 | |
Retirement savings plan expense | $ 119 | $ 109 | $ 105 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
10 year actual rate of return | 5.10% | 5.70% | 6.00% |
Company contributions | $ 343 | $ 328 | |
Expected employer contribution next year | 327 | ||
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Company contributions | 26 | $ 29 | |
Expected employer contribution next year | $ 15 |
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Funded Status: | |||
Noncurrent liability | $ (2,444) | $ (1,884) | |
Pension Plan | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 18,547 | 15,312 | |
Actual return on plan assets | 2,736 | 3,713 | |
Company contributions | 343 | 328 | |
Benefits and expenses paid | (867) | (806) | |
Fair value of plan assets at end of year | 20,759 | 18,547 | $ 15,312 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 20,525 | 17,407 | |
Service cost for benefits earned | 530 | 443 | 514 |
Interest cost | 713 | 758 | 687 |
Actuarial loss | 2,271 | 2,723 | |
Plan amendments | 0 | 0 | |
Benefits and expenses paid | (867) | (806) | |
Benefit obligation at end of year | 23,172 | 20,525 | 17,407 |
Funded Status: | |||
Current liability | (3) | (14) | |
Noncurrent liability | (2,410) | (1,964) | |
Net (liability) asset at end of year | (2,413) | (1,978) | |
Accumulated benefit obligation | 20,700 | 18,400 | |
PBOP Plans | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 2,678 | 2,258 | |
Actual return on plan assets | 379 | 474 | |
Company contributions | 26 | 29 | |
Plan participant contribution | 81 | 82 | |
Benefits and expenses paid | (169) | (165) | |
Fair value of plan assets at end of year | 2,995 | 2,678 | 2,258 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 1,832 | 1,745 | |
Service cost for benefits earned | 61 | 56 | 66 |
Interest cost | 63 | 76 | 69 |
Actuarial loss | (14) | 22 | |
Benefits and expenses paid | (149) | (150) | |
Federal subsidy on benefits paid | 3 | 2 | |
Plan participant contributions | 80 | 81 | |
Benefit obligation at end of year | 1,876 | 1,832 | $ 1,745 |
Funded Status: | |||
Noncurrent asset | 1,153 | 879 | |
Noncurrent liability | (34) | (33) | |
Net (liability) asset at end of year | 1,119 | 846 | |
PBOP Plans | Postretirement Life Insurance Plan | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 305 | ||
Fair value of plan assets at end of year | 343 | 305 | |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 337 | ||
Benefit obligation at end of year | $ 377 | $ 337 |
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | $ 530 | $ 443 | $ 514 |
Interest cost | 713 | 758 | 687 |
Expected return on plan assets | (1,044) | (906) | (1,021) |
Amortization of prior service cost | (6) | (6) | (6) |
Amortization of net actuarial loss | 3 | 3 | 5 |
Net periodic benefit cost | 196 | 292 | 179 |
Less: transfer to regulatory account | 136 | 42 | 157 |
Total expense recognized | 332 | 334 | 336 |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | 61 | 56 | 66 |
Interest cost | 63 | 76 | 69 |
Expected return on plan assets | (138) | (123) | (130) |
Amortization of prior service cost | 14 | 14 | 14 |
Amortization of net actuarial loss | (21) | (3) | (5) |
Net periodic benefit cost | $ (21) | $ 20 | $ 14 |
EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Defined Benefit Plan Disclosure [Line Items] | |||
Expected return on plan assets | 9.60% | ||
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.77% | 3.46% | 4.35% |
Rate of future compensation increases | 3.80% | 3.90% | 3.90% |
Expected return on plan assets | 5.10% | 5.70% | 6.00% |
Interest crediting rate for cash balance plan | 1.95% | 2.11% | 3.15% |
PBOP Plans | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.67% | 3.37% | 4.29% |
Expected return on plan assets | 3.10% | 3.50% | 3.60% |
PBOP Plans | Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 2.80% | 3.47% | 4.37% |
Expected return on plan assets | 6.10% | 6.60% | 6.80% |
EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details) |
Dec. 31, 2021 |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|---|
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | 100.00% | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 30.00% | 29.00% | |
Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2.00% | 5.00% | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | 8.00% | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 60.00% | 58.00% | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | 100.00% | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 28.00% | 33.00% | |
PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2.00% | 3.00% | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | 6.00% | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 62.00% | 58.00% | |
Forecast | Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | ||
Forecast | Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 30.00% | ||
Forecast | Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2.00% | ||
Forecast | Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8.00% | ||
Forecast | Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 60.00% | ||
Forecast | PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100.00% | ||
Forecast | PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 36.00% | ||
Forecast | PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 1.00% | ||
Forecast | PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 5.00% | ||
Forecast | PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 58.00% |
EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
---|---|---|---|
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | $ 24,003 | $ 21,324 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 12 | 15 | $ 8 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 20,993 | 18,636 | |
Assets measured at NAV | 20,759 | 18,547 | 15,312 |
Pension Plan | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 742 | 844 | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,875 | 1,650 | |
Pension Plan | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 2 | 1 | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 517 | 549 | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 9,633 | 8,655 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 5,194 | 5,038 | |
Pension Plan | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 334 | 613 | |
Pension Plan | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,875 | 1,650 | |
Pension Plan | Level 1 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 0 | |
Pension Plan | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 517 | 548 | |
Pension Plan | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 2,467 | 2,227 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 7,563 | 6,646 | |
Pension Plan | Level 2 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 408 | 231 | |
Pension Plan | Level 2 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 2 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 1 | |
Pension Plan | Level 2 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 1 | |
Pension Plan | Level 2 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 7,154 | 6,413 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 12 | 15 | |
Pension Plan | Level 3 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 3 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 12 | 15 | |
Pension Plan | Assets measured at NAV | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 8,224 | 6,937 | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 3,010 | 2,688 | |
Assets measured at NAV | 2,995 | 2,678 | $ 2,258 |
PBOP Plans | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 37 | 37 | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 173 | 151 | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 54 | 58 | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,197 | 1,069 | |
PBOP Plans | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 745 | 439 | |
PBOP Plans | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 37 | 37 | |
PBOP Plans | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 173 | 151 | |
PBOP Plans | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 54 | 58 | |
PBOP Plans | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 481 | 193 | |
PBOP Plans | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 715 | 875 | |
PBOP Plans | Level 2 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 2 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 715 | 875 | |
PBOP Plans | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 1 | |
PBOP Plans | Level 3 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
PBOP Plans | Level 3 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1 | 1 | |
PBOP Plans | Assets measured at NAV | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | $ 1,549 | $ 1,373 |
EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions |
12 Months Ended | |
---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
|
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Fair value of plan assets at beginning of year | $ 15 | $ 8 |
Actual return on plan assets: | ||
Relating to assets still held at the reporting date | 2 | 0 |
Relating to assets sold during the period | (3) | 0 |
Purchases, issuances, sales, and settlements: | ||
Purchases | 11 | 11 |
Settlements | (13) | (4) |
Fair value of plan assets at end of year | $ 12 | $ 15 |
EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
2021 | $ 831 |
2022 | 913 |
2023 | 948 |
2024 | 980 |
2025 | 1,009 |
Thereafter in the succeeding five years | 5,375 |
PBOP Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
2021 | 85 |
2022 | 89 |
2023 | 92 |
2024 | 93 |
2025 | 95 |
Thereafter in the succeeding five years | 471 |
Federal Subsidy | |
Defined Benefit Plan Disclosure [Line Items] | |
2021 | (6) |
2022 | (6) |
2023 | (6) |
2024 | (7) |
2025 | (7) |
Thereafter in the succeeding five years | $ (41) |
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Administrative services provided to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility revenues from | $ 3 | $ 4 | $ 4 |
Administrative services received from PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | 108 | 107 | 94 |
Utility employee benefit due to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | $ 34 | $ 42 | $ 76 |
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Related Party Transaction [Line Items] | ||
Current receivables | $ 35 | $ 60 |
Current payables | $ 46 | $ 118 |
WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Background) (Details) - Pacific Gas & Electric Co (Utility) |
Nov. 08, 2018
a
fatality
building
|
Oct. 30, 2017
a
fatality
structure
wildfire
|
---|---|---|
2018 Camp Fire | ||
Loss Contingencies [Line Items] | ||
Number of acres burned (acre) | a | 153,336 | |
Number of fatalities (fatality) | fatality | 85 | |
Number of other structures destroyed (structures) | building | 18,804 | |
Northern California Wildfire | ||
Loss Contingencies [Line Items] | ||
Number of acres burned (acre) | a | 245,000 | |
Number of fatalities (fatality) | fatality | 44 | |
Number of wildfires (wildfire) | wildfire | 21 | |
Number of structures destroyed (structure) | structure | 8,900 |
WILDFIRE-RELATED CONTINGENCIES (Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date) (Details) - USD ($) $ in Millions |
3 Months Ended | 6 Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
Jul. 01, 2020 |
Sep. 30, 2020 |
Jun. 30, 2020 |
Jan. 15, 2021 |
Dec. 31, 2020 |
Aug. 03, 2020 |
Jun. 12, 2020 |
Sep. 22, 2019 |
|
Loss Contingencies [Line Items] | ||||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000.0 | |||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | |||||||
Accrued environmental loss contingencies, current, elimination | $ 12,150.0 | |||||||
Plan of reorganization, tax benefits payment agreement | $ 1,350.0 | |||||||
Subrogation claims, professional fees | $ 55.0 | |||||||
Subsequent Event | ||||||||
Loss Contingencies [Line Items] | ||||||||
Payment of plan of reorganization, tax benefits payment agreement | $ 758.0 | |||||||
Settling Public Entities | ||||||||
Loss Contingencies [Line Items] | ||||||||
Litigation payment | 1,000.0 | |||||||
Litigation, segregated reimbursement fund | 10.0 | |||||||
Fire Victim Trust | ||||||||
Loss Contingencies [Line Items] | ||||||||
Litigation payment, fund, cash | 5,400.0 | |||||||
Litigation payment, additional funded, deferred | $ 1,350.0 | |||||||
Transfer of shares to Fire Victim Trust (in shares) | 477,000,000 | |||||||
Percentage of common stock owned, Fire Victim Trust if common issues additional shares | 22.19% | 22.19% | ||||||
Transfer of shares to Fire Victim Trust, additional (in shares) | 748,415 | |||||||
Subrogation Wildfire Trust | ||||||||
Loss Contingencies [Line Items] | ||||||||
Litigation payment, fund, cash | $ 11,000.0 | |||||||
Litigation payment | 43.0 | |||||||
Subrogation claims, professional fees | $ 52.0 | |||||||
Pacific Gas & Electric Co (Utility) | ||||||||
Loss Contingencies [Line Items] | ||||||||
Subrogation claims, professional fees | $ 53.0 | |||||||
Subrogation insurance claims | $ 11,000.0 | |||||||
Professional fees extinguished | 47.5 | |||||||
Pacific Gas & Electric Co (Utility) | All Other Wildfire-related Claims | ||||||||
Loss Contingencies [Line Items] | ||||||||
Wildfire-related claims | $ 13,500.0 | |||||||
Pacific Gas & Electric Co (Utility) | Public Entity Wildfire Claims | Settling Public Entities | ||||||||
Loss Contingencies [Line Items] | ||||||||
Wildfire-related claims | $ 1,000.0 |
WILDFIRE-RELATED CONTINGENCIES (Plan Support Agreements with Public Entities) (Details) - Public Entity Wildfire Claims - Settled Litigation $ in Millions |
Jun. 18, 2019
USD ($)
|
---|---|
Loss Contingencies [Line Items] | |
Settlement reached | $ 1,000 |
Fund to support defense or resolution of claims per plan support agreement | $ 10 |
WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details) $ in Millions |
Jul. 01, 2020
USD ($)
|
Sep. 22, 2019
USD ($)
|
Dec. 31, 2020
USD ($)
|
Jun. 12, 2020 |
Dec. 06, 2019
USD ($)
|
---|---|---|---|---|---|
Loss Contingencies [Line Items] | |||||
TCC claims settlement, amount | $ 11,000 | $ 11,000 | |||
Subrogation claims, professional fees | $ 55 | ||||
Fire Victim Trust | |||||
Loss Contingencies [Line Items] | |||||
Percentage of common stock owned, Fire Victim Trust if common issues additional shares | 22.19% | 22.19% | |||
Pacific Gas & Electric Co (Utility) | |||||
Loss Contingencies [Line Items] | |||||
Subrogation claims, professional fees | $ 53 | ||||
Cash | $ 1,350 | ||||
Multiplier, normalized estimated net income | 14.9 | ||||
Number of fully diluted shares of the reorganized, percentage | 20.90% | ||||
Pacific Gas & Electric Co (Utility) | Effective Date | |||||
Loss Contingencies [Line Items] | |||||
Cash contribution by company | $ 5,400 | ||||
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2021 | |||||
Loss Contingencies [Line Items] | |||||
Cash | 758 | ||||
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2022 | |||||
Loss Contingencies [Line Items] | |||||
Cash | $ 592 |
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire and 2020 Zogg Fire) (Details) $ in Millions |
12 Months Ended | |||||
---|---|---|---|---|---|---|
Nov. 04, 2019
numberOfPeople
|
Dec. 31, 2020
USD ($)
|
Feb. 24, 2021
numberOfPlaintiff
plaintiff
complaint
|
Sep. 27, 2020
a
structure
fatality
injury
|
Dec. 31, 2019
USD ($)
|
Oct. 23, 2019
a
structure
injury
customer
numberOfFatality
|
|
Loss Contingencies [Line Items] | ||||||
Cumulative reimbursements from insurance policies | $ 649.0 | |||||
Insurance receivable | 674.0 | $ 2,238.0 | ||||
2019 Kincade Fire | ||||||
Loss Contingencies [Line Items] | ||||||
Number of acres burned (acre) | a | 77,758 | |||||
Number of fatalities (fatality) | numberOfFatality | 0 | |||||
Number of injuries | injury | 4 | |||||
Number of structures destroyed (structure) | structure | 374 | |||||
Number of residences destroyed (residence) | structure | 174 | |||||
Number of commercial structures destroyed (structure) | structure | 11 | |||||
Number of other structures destroyed (structures) | structure | 189 | |||||
Number of structures damaged (structure) | structure | 60 | |||||
Number of residential structures damaged (structure) | structure | 35 | |||||
Number of commercial structures damaged (structure) | structure | 1 | |||||
Number of other structures damaged (structure) | structure | 24 | |||||
Number of people part of mandatory evacuation order | numberOfPeople | 200,000 | |||||
Number of customers without power | customer | 27,837 | |||||
Potential loss contingency | 625.0 | |||||
Loss contingency, claim eligibility requirement amount | 1,000.0 | |||||
Cumulative reimbursements from insurance policies | 430.0 | |||||
Insurance receivable | 430.0 | 0.0 | ||||
2019 Kincade Fire | Subsequent Event | ||||||
Loss Contingencies [Line Items] | ||||||
Number of complaint | complaint | 22 | |||||
Number of plaintiffs represented by complaints | plaintiff | 504 | |||||
2020 Zogg Fire | ||||||
Loss Contingencies [Line Items] | ||||||
Number of acres burned (acre) | a | 56,338 | |||||
Number of fatalities (fatality) | fatality | 4 | |||||
Number of injuries | injury | 1 | |||||
Number of structures destroyed (structure) | structure | 204 | |||||
Number of structures damaged (structure) | structure | 27 | |||||
Potential loss contingency | 275.0 | |||||
Loss contingency, claim eligibility requirement amount | 1,000.0 | |||||
Cumulative reimbursements from insurance policies | 219.0 | |||||
Number of single family homes destroyed | structure | 63 | |||||
Insurance receivable | 219.0 | $ 0.0 | ||||
Initial self-insured retention per occurrence | 60.0 | |||||
Legal fees | 4.0 | |||||
2020 Zogg Fire | Maximum | ||||||
Loss Contingencies [Line Items] | ||||||
Cumulative reimbursements from insurance policies | $ 867.5 | |||||
2020 Zogg Fire | Subsequent Event | ||||||
Loss Contingencies [Line Items] | ||||||
Number of complaint | complaint | 6 | |||||
Number of plaintiffs represented by complaints | numberOfPlaintiff | 240 |
WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions |
12 Months Ended | |||
---|---|---|---|---|
Jul. 01, 2020 |
Dec. 31, 2020 |
Jul. 31, 2020 |
Dec. 31, 2019 |
|
Loss Contingencies [Line Items] | ||||
Prepaid insurance | $ 536.0 | |||
Insurance premium costs, recovery, coverage amount | 1,400.0 | |||
Insurance receivable | 674.0 | $ 2,238.0 | ||
Insurance Coverage For Wildfire and Non-Wildfire Events | ||||
Loss Contingencies [Line Items] | ||||
Costs for insurance coverage | $ 859.0 | |||
Insurance Coverage For Wildfire and Non-Wildfire Events | August 1, 2019 through July 31, 2020 | ||||
Loss Contingencies [Line Items] | ||||
Costs for insurance coverage | 212.0 | |||
Insurance Coverage for Wildfire Events | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | $ 867.5 | |||
Initial self-insured retention per occurrence | 60.0 | |||
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020 | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | 430.0 | |||
Initial self-insured retention per occurrence | 10.0 | |||
Insurance Coverage for Wildfire Events | August 1, 2019 through September 2, 2020 | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | 825.0 | |||
Insurance Coverage for Wildfire Events | July 1, 2020 - June 30, 2021 | ||||
Loss Contingencies [Line Items] | ||||
Reinsurance | 42.5 | |||
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2019 through July 31, 2020 | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | 520.0 | |||
Initial self-insured retention per occurrence | 10.0 | |||
Insurance Coverage For Non-Wildfire Liabilities | September 3, 2019 through September 2, 2020 | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | 480.0 | |||
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2020 - July 31, 2021 | ||||
Loss Contingencies [Line Items] | ||||
Liability insurance coverage | 700.0 | |||
Initial self-insured retention per occurrence | $ 10.0 | |||
2019 Kincade Fire | ||||
Loss Contingencies [Line Items] | ||||
Insurance receivable | 430.0 | 0.0 | ||
2020 Zogg Fire | ||||
Loss Contingencies [Line Items] | ||||
Initial self-insured retention per occurrence | 60.0 | |||
Insurance receivable | 219.0 | 0.0 | ||
2017 Northern California wildfires | ||||
Loss Contingencies [Line Items] | ||||
Insurance receivable | 25.0 | $ 808.0 | ||
Estimated insurance recoveries, pending to receive | $ 25.0 |
WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2020
USD ($)
| |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | $ 2,238 |
Accrued insurance recoveries | 649 |
Reimbursements | (2,213) |
Insurance Receivable, Ending Balance | 674 |
2020 Zogg Fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 0 |
Accrued insurance recoveries | 219 |
Reimbursements | 0 |
Insurance Receivable, Ending Balance | 219 |
2019 Kincade Fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 0 |
Accrued insurance recoveries | 430 |
Reimbursements | 0 |
Insurance Receivable, Ending Balance | 430 |
2018 Camp Fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 1,380 |
Accrued insurance recoveries | 0 |
Reimbursements | (1,380) |
Insurance Receivable, Ending Balance | 0 |
2017 Northern California wildfires | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 808 |
Accrued insurance recoveries | 0 |
Reimbursements | (783) |
Insurance Receivable, Ending Balance | 25 |
2015 Butte Fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 50 |
Accrued insurance recoveries | 0 |
Reimbursements | (50) |
Insurance Receivable, Ending Balance | $ 0 |
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2018 Camp Fire and 2017 Northern California Wildfires - USD ($) $ in Millions |
Apr. 30, 2020 |
Jul. 08, 2019 |
---|---|---|
Loss Contingencies [Line Items] | ||
Customer Harm Threshold, potential regulatory adjustment, percentage | 20.00% | |
Customer Harm Threshold, Potential regulatory adjustment, percentage of total disallowed wildlife liability | 5.00% | |
Customer Harm Threshold, post-emergence transaction, securitized | $ 7,500 | |
Customer Harm Threshold, post-emergence transaction, debt retirement | 6,000 | |
Customer Harm Threshold, post-emergence transaction, debt payment acceleration | $ 592 |
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties |
Feb. 24, 2021
notice
|
Nov. 20, 2017
lawsuit
|
Nov. 16, 2017
lawsuit
|
---|---|---|---|
Subsequent Event | |||
Loss Contingencies [Line Items] | |||
Number of causes of action (causes) | notice | 2 | ||
Derivative Lawsuits Filed in the San Francisco County Superior Court | |||
Loss Contingencies [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit | 2 | 2 |
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation and Debt Claims) (Details) |
Dec. 31, 2020
lawsuit
|
Feb. 22, 2019
offering
|
Jun. 30, 2018
lawsuit
|
---|---|---|---|
Wildfire-Related Class Action | |||
Loss Contingencies [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | 2 | ||
Number of public offerings of notes with complaints against underwriters (offering) | offering | 4 | ||
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt | |||
Loss Contingencies [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | 3 |
WILDFIRE-RELATED CONTINGENCIES (De-energization Class Action) (Details) - De-energization Class Action - Subsequent Event $ in Millions |
Feb. 16, 2021
USD ($)
|
---|---|
Loss Contingencies [Line Items] | |
Litigation settlement, amount awarded from other party | $ 10 |
Litigation settlement, approval of settlement, escrow deposit, number of days | 14 days |
WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) $ in Millions |
12 Months Ended | ||||
---|---|---|---|---|---|
Jul. 21, 2020
USD ($)
|
Mar. 17, 2020
USD ($)
count
|
Dec. 31, 2020
USD ($)
|
Dec. 31, 2019
USD ($)
|
Dec. 31, 2018
USD ($)
|
|
Loss Contingencies [Line Items] | |||||
Wildfire fund expense | $ 413.0 | $ 0.0 | $ 0.0 | ||
Pacific Gas & Electric Co (Utility) | |||||
Loss Contingencies [Line Items] | |||||
Wildfire fund expense | $ 413.0 | $ 0.0 | $ 0.0 | ||
Pacific Gas & Electric Co (Utility) | Complaints Brought By Butte County District Attorney | Loss from Wildfires | |||||
Loss Contingencies [Line Items] | |||||
Number of guilty involuntary manslaughter pleas | count | 84 | ||||
Wildfire fund expense | $ 3.5 | $ 3.5 | |||
Reimbursement of investigation fees | $ 0.5 | 0.5 | |||
Committed funds for impacted residence | $ 15.0 | ||||
Committed funds for impacted residence, minimum term | 5 years |
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions |
Jan. 14, 2021 |
Aug. 23, 2019 |
Dec. 31, 2020 |
Jul. 01, 2020 |
Jul. 12, 2019 |
---|---|---|---|---|---|
Loss Contingencies [Line Items] | |||||
Disallowance cap, transmission and distribution equity rate base | $ 2,700 | ||||
Initial safety certification, period | 12 months | ||||
Initial safety certification, documentation provided, period | 90 days | ||||
Expected capitalization, proceeds of bond | $ 10,500 | ||||
Expected capitalization, initial contribution | 7,500 | ||||
Expected capitalization, annual contribution | 300 | ||||
Expected wildfire fund allocation metric, percentage | 64.20% | ||||
Expected wildfire fund allocation metric, initial contribution | $ 4,800 | ||||
Expected wildfire fund allocation metric, annual contributions | 193 | ||||
Allocation | $ 3,210 | ||||
Initial contribution payment | $ 4,800 | ||||
Annual contribution, first payment | $ 193 | ||||
Annual contribution, second payment | $ 193 | ||||
Subsequent Event | |||||
Loss Contingencies [Line Items] | |||||
Initial safety certification, valid period | 12 months |
OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Narrative) (Details) $ in Millions |
Jan. 04, 2021
party
|
Dec. 31, 2021
USD ($)
|
Dec. 31, 2020
USD ($)
|
Jun. 08, 2020
party
|
Apr. 20, 2020
USD ($)
|
Dec. 17, 2019
USD ($)
|
---|---|---|---|---|---|---|
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures, disallowed costs | $ 1,625 | |||||
Expenses and capital expenditures, disallowed capital, approved | $ 198 | |||||
Shareholder-funded system enhancement initiatives, approved | 64 | |||||
Fine payable to general fund, suspended | 200 | |||||
Number of parties filed separate applications for rehearing | party | 2 | |||||
Wildfire mitigation plan memorandum account | ||||||
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures, disallowed capital, approved | $ 198 | |||||
Subsequent Event | ||||||
Loss Contingencies [Line Items] | ||||||
Number of parties filed petition for review of the CUPC decision | party | 1 | |||||
Pacific Gas & Electric Co (Utility) | ||||||
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures | 1,625 | |||||
Pacific Gas & Electric Co (Utility) | Wildfire mitigation plan memorandum account | ||||||
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures, charges recorded | $ 152 | |||||
Pacific Gas & Electric Co (Utility) | Forecast | Wildfire mitigation plan memorandum account | ||||||
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures, charges recorded | $ 46 | |||||
Pacific Gas & Electric Co (Utility) | Pending Litigation | Unfavorable Regulatory Action | ||||||
Loss Contingencies [Line Items] | ||||||
Expenses and capital expenditures | $ 1,625 | |||||
Shareholder-funded system enhancement initiatives, amount | $ 50 |
OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Legal Obligation) (Details) - Pacific Gas & Electric Co (Utility) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Loss Contingencies [Line Items] | |
Expense | $ 1,222 |
Capital | 403 |
Total | 1,625 |
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) | |
Loss Contingencies [Line Items] | |
Expense | 236 |
Capital | 0 |
Total | 236 |
Transmission Safety Inspections and Repairs Expense (TO) | |
Loss Contingencies [Line Items] | |
Expense | 433 |
Capital | 0 |
Total | 433 |
Vegetation Management Support Costs (FHPMA) | |
Loss Contingencies [Line Items] | |
Expense | 36 |
Capital | 0 |
Total | 36 |
2017 Northern California Wildfires CEMA Expense and Capital (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 82 |
Capital | 66 |
Total | 148 |
2018 Camp Fire CEMA Expense (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 435 |
Capital | 0 |
Total | 435 |
2018 Camp Fire CEMA Capital for Restoration (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 0 |
Capital | 253 |
Total | 253 |
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) | |
Loss Contingencies [Line Items] | |
Expense | 0 |
Capital | 84 |
Total | $ 84 |
OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details) |
Sep. 21, 2018 |
May 21, 2020 |
---|---|---|
Loss Contingencies [Line Items] | ||
Approved depreciation rate | 2.94% | |
Requested depreciation rate | 3.25% | |
Labor rates, allocation percentage | 6.15% | |
Direct assignment, percentage | 8.84% | |
Pacific Gas & Electric Co (Utility) | Electric | ||
Loss Contingencies [Line Items] | ||
Requested revenue rate | 98.85% |
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Commitments and Contingencies Disclosure [Abstract] | ||
Accrued legal liabilities | $ 144 | $ 116 |
OTHER CONTINGENCIES AND COMMITMENTS (PSPS Class Action) (Details) $ in Billions |
Dec. 19, 2019
USD ($)
|
---|---|
PSPS Class Action | Pending Litigation | Pacific Gas & Electric Co (Utility) | |
Loss Contingencies [Line Items] | |
Loss contingency, damages sought | $ 2.5 |
OTHER CONTINGENCIES AND COMMITMENTS (GT&S Capital Expenditures 2011-2014 and CZU Lightning Complex Fire Notice of Violations) (Details) $ in Millions |
1 Months Ended | ||
---|---|---|---|
Jun. 23, 2016
USD ($)
|
Feb. 08, 2021
notice
|
Jul. 31, 2020
USD ($)
|
|
Disallowance of Plant Costs | |||
Loss Contingencies [Line Items] | |||
Gas transmission and storage capital disallowance | $ 696 | ||
Permanently disallowed capital | 120 | ||
Amount subject to audit | $ 576 | ||
Capital expenditures for future recovery | $ 512 | ||
CZU Lightning Complex Fire Notice of Violations | Subsequent Event | |||
Loss Contingencies [Line Items] | |||
Number of notices issued of violation | notice | 5 |
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
---|---|---|
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract] | ||
Topock natural gas compressor station | $ 303 | $ 362 |
Hinkley natural gas compressor station | 132 | 138 |
Former manufactured gas plant sites owned by the Utility or third parties | 659 | 568 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites | 111 | 101 |
Fossil fuel-fired generation facilities and sites | 96 | 106 |
Total environmental remediation liability | $ 1,301 | $ 1,275 |
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 986 |
Topock Site | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 216 |
Topock Site | Pacific Gas & Electric Co (Utility) | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Hinkley Natural Gas Compressor Station | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 138 |
Former Manufactured Gas Plant | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 460 |
Former Manufactured Gas Plant | Pacific Gas & Electric Co (Utility) | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Utility Owned Generation Facilities and Third Party Disposal Sites | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 67 |
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co (Utility) | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90.00% |
Fossil Fuel Fired Generation | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 43 |
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions |
8 Months Ended | 12 Months Ended |
---|---|---|
Feb. 24, 2021
outage
|
Dec. 31, 2020
USD ($)
nuclear_generating_unit
|
|
Long-term Purchase Commitment [Line Items] | ||
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit | 2 | |
Maximum total payment incurred per event under the loss sharing program | $ 450 | |
Humboldt Bay Unit | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of property damage coverage provided by NEIL | 50 | |
Amount of liability insurance for Humboldt Bay Unit 3 | 53 | |
Diablo Canyon | ||
Long-term Purchase Commitment [Line Items] | ||
Maximum public liability per nuclear incident under Price-Anderson Act | 13,800 | |
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act | 450 | |
Maximum annual payment incurred per event under the loss sharing program | 275 | |
Coverage for purchased public liability insurance, per incident | $ 41 | |
Period for inflation adjustment | 5 years | |
Diablo Canyon | Subsequent Event | ||
Long-term Purchase Commitment [Line Items] | ||
Number of outages experienced | outage | 4 | |
Nuclear Incident | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | $ 3,200 | |
Nuclear Incident | Humboldt Bay Unit | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of indemnification from the nuclear regulatory commission for public liability arising from nuclear incidents | 500 | |
Non-Nuclear Incident | ||
Long-term Purchase Commitment [Line Items] | ||
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | 2,700 | |
European Mutual Association for Nuclear Insurance | ||
Long-term Purchase Commitment [Line Items] | ||
Full insurance policy limit | 200 | |
Potential premium obligation | 4 | |
Nuclear Electric Insurance Limited | ||
Long-term Purchase Commitment [Line Items] | ||
Potential premium obligation | $ 43 |
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Long-term Purchase Commitment [Line Items] | |
2021 | $ 3,447 |
2022 | 2,860 |
2023 | 2,488 |
2024 | 2,303 |
2025 | 2,244 |
Thereafter | 21,841 |
Total purchase commitments | 35,183 |
Renewable Energy | |
Long-term Purchase Commitment [Line Items] | |
2021 | 2,270 |
2022 | 2,042 |
2023 | 1,997 |
2024 | 1,972 |
2025 | 1,962 |
Thereafter | 21,335 |
Total purchase commitments | 31,578 |
Conventional Energy | |
Long-term Purchase Commitment [Line Items] | |
2021 | 582 |
2022 | 511 |
2023 | 223 |
2024 | 72 |
2025 | 70 |
Thereafter | 281 |
Total purchase commitments | 1,739 |
Other | |
Long-term Purchase Commitment [Line Items] | |
2021 | 65 |
2022 | 62 |
2023 | 61 |
2024 | 61 |
2025 | 61 |
Thereafter | 41 |
Total purchase commitments | 351 |
Natural Gas | |
Long-term Purchase Commitment [Line Items] | |
2021 | 466 |
2022 | 191 |
2023 | 158 |
2024 | 151 |
2025 | 151 |
Thereafter | 184 |
Total purchase commitments | 1,301 |
Nuclear Fuel | |
Long-term Purchase Commitment [Line Items] | |
2021 | 64 |
2022 | 54 |
2023 | 49 |
2024 | 47 |
2025 | 0 |
Thereafter | 0 |
Total purchase commitments | $ 214 |
OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Power Purchases and Electric Capacity | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Costs incurred for power purchases and electric capacity | $ 2,900 | $ 3,000 | $ 3,100 |
Nuclear Fuel | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Payments for nuclear fuel | 111 | 74 | 73 |
Gas Contracts | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Cost of goods | $ 800 | $ 900 | $ 600 |
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions |
Dec. 31, 2020
USD ($)
|
---|---|
Commitments and Contingencies Disclosure [Abstract] | |
2021 | $ 40 |
2022 | 30 |
2023 | 46 |
2024 | 65 |
2025 | 60 |
Thereafter | 2,924 |
Total minimum lease payments | $ 3,165 |
OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Commitments and Contingencies Disclosure [Abstract] | |||
Payments for other commitments | $ 45 | $ 48 | $ 43 |
Operating Leased Assets [Line Items] | |||
Present value of fixed capacity payments, portion classified as current liabilities | 533 | 556 | |
Present value of fixed capacity payments, portion classified as noncurrent liabilities | 1,208 | 1,730 | |
Qualifying Facilities | |||
Operating Leased Assets [Line Items] | |||
Capitalized asset for fixed capacity payments for corresponding assets | 7 | 9 | |
Capitalized asset for fixed capacity payments, accumulated amortization | 11 | 9 | |
Present value of fixed capacity payments, portion classified as current liabilities | 2 | 2 | |
Present value of fixed capacity payments, portion classified as noncurrent liabilities | $ 5 | $ 7 | |
Minimum | |||
Operating Leased Assets [Line Items] | |||
Extension option for operating leases | 1 year | ||
Maximum | |||
Operating Leased Assets [Line Items] | |||
Extension option for operating leases | 5 years |
OTHER CONTINGENCIES AND COMMITMENTS (Oakland Headquarters Lease) (Details) ft² in Thousands, $ in Millions |
Oct. 23, 2020
USD ($)
|
Jun. 05, 2020
USD ($)
ft²
|
---|---|---|
Commitments and Contingencies Disclosure [Abstract] | ||
Rentable square feet | ft² | 910 | |
Lease, option payment letter of credit | $ 75 | |
Lease, security letter of credit | $ 75 | |
Term of contract | 34 years 11 months | |
Purchase options, land, value | $ 892 |
SUBSEQUENT EVENTS (Details) - Pacific Gas & Electric Co (Utility) - Subsequent Event - SBA Communications Corporation - Wireless Licenses $ in Millions |
Feb. 16, 2021
USD ($)
transmissionTower
|
---|---|
Subsequent Event [Line Items] | |
Duration of contract | 100 years |
Proceeds from sale of transmission tower license | $ 973 |
Proceeds from sale of transmission tower license, closing | 954 |
Proceeds from sale of transmission tower license, initial cash proceeds | $ 945 |
Other tower, duration of contract | 15 years |
Minimum | Effective Date Towers | |
Subsequent Event [Line Items] | |
Number of electric transmission towers | transmissionTower | 700 |
Number of other electric transmission towers | transmissionTower | 28,000 |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Operating expenses | $ (16,714) | $ (27,223) | $ (26,459) |
Interest income | 39 | 82 | 76 |
Interest expense | (1,260) | (934) | (929) |
Other income, net | 483 | 250 | 424 |
Reorganization items, net | (1,959) | (346) | 0 |
Loss Before Income Taxes | (942) | (11,042) | (10,129) |
Income tax provision (benefit) | 362 | (3,400) | (3,292) |
Loss Attributable to Common Shareholders | (1,318) | (7,656) | (6,851) |
Other Comprehensive Income (Loss) | |||
Pension and other postretirement benefit plans obligations | (17) | (1) | 4 |
Total other comprehensive income (loss) | $ (17) | $ (1) | $ 4 |
Weighted Average Common Shares Outstanding, Basic (in shares) | 1,257 | 528 | 517 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 1,257 | 528 | 517 |
Net Loss Per Common Share, Basic (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Net Loss Per Common Share, Diluted (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Pension and other postretirement benefit plans obligations, tax | $ 7 | $ 0 | $ 2 |
PG&E Corporation | |||
Operating expenses | (103) | (114) | (91) |
Interest income | 0 | 1 | 2 |
Interest expense | (149) | (21) | (15) |
Other income, net | 13 | 10 | (2) |
Reorganization items, net | (1,649) | (26) | 0 |
Equity in earnings of subsidiaries | 411 | (7,622) | (6,832) |
Loss Before Income Taxes | (1,350) | (7,634) | (6,848) |
Income tax provision (benefit) | (46) | 8 | 3 |
Loss Attributable to Common Shareholders | (1,304) | (7,642) | (6,851) |
Other Comprehensive Income (Loss) | |||
Pension and other postretirement benefit plans obligations | (17) | (1) | 4 |
Total other comprehensive income (loss) | (17) | (1) | 4 |
Comprehensive Loss | $ (1,321) | $ (7,643) | $ (6,847) |
Weighted Average Common Shares Outstanding, Basic (in shares) | 1,257 | 528 | 517 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 1,257 | 528 | 513 |
Net Loss Per Common Share, Basic (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Net Loss Per Common Share, Diluted (in dollars per share) | $ (1.05) | $ (14.50) | $ (13.25) |
Pension and other postretirement benefit plans obligations, tax | $ 7 | $ 0 | $ 2 |
PG&E Corporation | Administrative service revenue | |||
Revenue | $ 127 | $ 138 | $ 90 |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
---|---|---|---|
Current Assets | |||
Cash and cash equivalents | $ 484 | $ 1,570 | $ 1,668 |
Other | 1,334 | 639 | |
Total current assets | 9,602 | 10,165 | |
Noncurrent Assets | |||
Equipment | 93,894 | 88,090 | |
Accumulated depreciation | (27,758) | (26,455) | |
Net property, plant, and equipment | 66,136 | 61,635 | |
Operating lease right of use asset | 1,741 | 2,286 | |
TOTAL ASSETS | 97,856 | 85,196 | |
Current Liabilities | |||
Long-term debt, classified as current | 28 | 0 | |
Operating lease liabilities | 533 | 556 | |
Other current liabilities | 2,256 | 1,254 | |
Total current liabilities | 13,581 | 7,631 | |
Noncurrent Liabilities | |||
Debtor-in-possession financing | 37,288 | 0 | |
Operating lease liabilities | 1,208 | 1,730 | |
Other | 3,848 | 2,573 | |
Total noncurrent liabilities | 63,022 | 21,631 | |
Liabilities Subject to Compromise | 0 | 50,546 | |
Common Shareholders’ Equity | |||
Common stock, no par value | 30,224 | 13,038 | |
Reinvested earnings | (9,196) | (7,892) | |
Accumulated other comprehensive income (loss) | (27) | (10) | |
Total shareholders' equity | 21,001 | 5,136 | |
TOTAL LIABILITIES AND EQUITY | 97,856 | 85,196 | |
PG&E Corporation | |||
Current Assets | |||
Cash and cash equivalents | 223 | 448 | |
Advances to affiliates | 48 | 120 | |
Income taxes receivable | 12 | 12 | |
Other | 13 | 11 | |
Total current assets | 296 | 591 | |
Noncurrent Assets | |||
Equipment | 2 | 2 | |
Accumulated depreciation | (2) | (2) | |
Net property, plant, and equipment | 0 | 0 | |
Investments in subsidiaries | 25,244 | 5,102 | |
Other investments | 186 | 173 | |
Operating lease right of use asset | 3 | 6 | |
Deferred income taxes | 237 | 187 | |
Total noncurrent assets | 25,670 | 5,468 | |
TOTAL ASSETS | 25,966 | 6,059 | |
Current Liabilities | |||
Long-term debt, classified as current | 28 | 0 | |
Accounts payable – other | 49 | 47 | |
Operating lease liabilities | 3 | 3 | |
Other current liabilities | 72 | 3 | |
Total current liabilities | 152 | 53 | |
Noncurrent Liabilities | |||
Debtor-in-possession financing | 4,624 | 0 | |
Operating lease liabilities | 0 | 3 | |
Other | 191 | 58 | |
Total noncurrent liabilities | 4,815 | 61 | |
Liabilities Subject to Compromise | 0 | 810 | |
Common Shareholders’ Equity | |||
Common stock, no par value | 30,224 | 13,038 | |
Reinvested earnings | (9,198) | (7,893) | |
Accumulated other comprehensive income (loss) | (27) | (10) | |
Total shareholders' equity | 20,999 | 5,135 | |
TOTAL LIABILITIES AND EQUITY | $ 25,966 | $ 6,059 |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ in Millions |
1 Months Ended | 12 Months Ended | ||||
---|---|---|---|---|---|---|
Jul. 01, 2020 |
Jun. 25, 2020 |
Jul. 31, 2020 |
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
Cash Flows from Operating Activities | ||||||
Net Loss | $ (1,304) | $ (7,642) | $ (6,837) | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Deferred income taxes and tax credits, net | 1,097 | (2,948) | (2,532) | |||
Reorganization items, net | 1,458 | 108 | 0 | |||
Liabilities subject to compromise | 413 | 12,222 | 0 | |||
Net cash provided by (used in) operating activities | (19,130) | 4,816 | 4,752 | |||
Cash Flows from Investing Activities | ||||||
Net cash used in investing activities | (7,748) | (6,378) | (6,564) | |||
Cash Flows From Financing Activities: | ||||||
Debtor-in-possession credit facility debt issuance costs | (6) | (113) | 0 | |||
Bridge facility financing fees | (73) | 0 | 0 | |||
Borrowings under credit facilities | 8,554 | 0 | 3,960 | |||
Repayments under credit facilities | (3,949) | 0 | (775) | |||
Net repayments of commercial paper | 0 | 0 | (182) | |||
Repayment of long-term debt | (764) | 0 | (795) | |||
Equity Units issued | $ 9,000 | $ 3,970 | $ 9,000 | 1,304 | 0 | 0 |
Net cash provided by financing activities | 25,928 | 1,464 | 3,031 | |||
Net change in cash, cash equivalents, and restricted cash | (950) | (98) | 1,219 | |||
Cash, cash equivalents, and restricted cash at January 1 | 1,577 | 1,675 | 456 | |||
Cash, cash equivalents, and restricted cash at December 31 | 627 | 1,577 | 1,675 | |||
Cash paid for: | ||||||
Interest, net of amounts capitalized | (1,563) | (10) | (786) | |||
Income taxes, net | 0 | 0 | (49) | |||
Supplemental disclosures of noncash investing and financing activities | ||||||
Operating lease liabilities arising from obtaining ROU assets | 13 | 2,816 | 0 | |||
Common stock issued in satisfaction of liabilities | 8,276 | 0 | 0 | |||
PG&E Corporation | ||||||
Cash Flows from Operating Activities | ||||||
Net Loss | (1,304) | (7,642) | (6,851) | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||
Stock-based compensation amortization | 28 | 43 | 78 | |||
Equity in earnings of subsidiaries | (412) | 7,622 | 6,833 | |||
Deferred income taxes and tax credits, net | (50) | 0 | (62) | |||
Reorganization items, net | 1,548 | 11 | 0 | |||
Current income taxes receivable/payable | 0 | 6 | 9 | |||
Liabilities subject to compromise | 12 | 28 | 0 | |||
Other | 97 | (62) | 41 | |||
Net cash provided by (used in) operating activities | (81) | 6 | 48 | |||
Cash Flows from Investing Activities | ||||||
Investment in subsidiaries | (12,986) | 0 | (45) | |||
Net cash used in investing activities | (12,986) | 0 | (45) | |||
Cash Flows From Financing Activities: | ||||||
Debtor-in-possession credit facility debt issuance costs | 0 | (16) | 0 | |||
Bridge facility financing fees | (40) | 0 | 0 | |||
Borrowings under credit facilities | 0 | 0 | 425 | |||
Repayments under credit facilities | 0 | 0 | (125) | |||
Net repayments of commercial paper | 0 | 0 | (132) | |||
Short-term debt financing | 0 | 0 | 350 | |||
Proceeds from issuance of long-term debt | 4,660 | 0 | 0 | |||
Repayment of long-term debt | (664) | 0 | (350) | |||
Common stock issued | 7,582 | 85 | 200 | |||
Equity Units issued | 1,304 | 0 | 0 | |||
Net cash provided by financing activities | 12,842 | 69 | 368 | |||
Net change in cash, cash equivalents, and restricted cash | (225) | 75 | 371 | |||
Cash, cash equivalents, and restricted cash at January 1 | 448 | 373 | 2 | |||
Cash, cash equivalents, and restricted cash at December 31 | 223 | 448 | 373 | |||
Cash paid for: | ||||||
Interest, net of amounts capitalized | (105) | (3) | (13) | |||
Income taxes, net | 0 | 0 | 10 | |||
Supplemental disclosures of noncash investing and financing activities | ||||||
Operating lease liabilities arising from obtaining ROU assets | 0 | 9 | 0 | |||
Common stock issued in satisfaction of liabilities | $ 8,276 | $ 0 | $ 0 |
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2020 |
Dec. 31, 2019 |
Dec. 31, 2018 |
|
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | $ 43 | $ 56 | $ 64 |
Charged to Costs and Expenses | 138 | 0 | 34 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 35 | 13 | 42 |
Balance at End of Period | $ 146 | $ 43 | $ 56 |
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