Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2022 | |
Audit Information [Abstract] | |
Auditor Firm ID | 34 |
Auditor Name | DELOITTE & TOUCHE LLP |
Auditor Location | San Francisco, California |
Cover Page
Cover Page - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Feb. 16, 2023 | Jun. 30, 2022 | |
Document Type | 10-K | ||
Document Annual Report | true | ||
Current Fiscal Year End Date | --12-31 | ||
Document Period End Date | Dec. 31, 2022 | ||
Document Transition Report | false | ||
Entity File Number | 1-12609 | ||
Entity Incorporation, State or Country Code | CA | ||
Entity Tax Identification Number | 94-3234914 | ||
Entity Address, Address Line One | 300 Lakeside Drive | ||
Entity Address, City or Town | Oakland, | ||
Entity Address, State or Province | CA | ||
Entity Address, Postal Zip Code | 94612 | ||
City Area Code | 415 | ||
Local Phone Number | 973-1000 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Bankruptcy Proceedings, Reporting Current | true | ||
Entity Public Float | $ 20,819 | ||
Entity Common Stock, Shares Outstanding (in shares) | 2,466,208,388 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved: Designated portions of the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14) | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2022 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | PG&E CORP | ||
Entity Central Index Key | 0001004980 | ||
Pacific Gas & Electric Co (Utility) | |||
Document Type | 10-K | ||
Entity File Number | 1-2348 | ||
Entity Incorporation, State or Country Code | CA | ||
Entity Tax Identification Number | 94-0742640 | ||
Entity Address, Address Line One | 300 Lakeside Drive | ||
Entity Address, City or Town | Oakland, | ||
Entity Address, State or Province | CA | ||
Entity Address, Postal Zip Code | 94612 | ||
City Area Code | 415 | ||
Local Phone Number | 973-1000 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Entity Shell Company | false | ||
Entity Bankruptcy Proceedings, Reporting Current | true | ||
Entity Common Stock, Shares Outstanding (in shares) | 264,374,809 | ||
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved: Designated portions of the Joint Proxy Statement relating to the 2023 Annual Meetings of Shareholders Part III (Items 10, 11, 12, 13 and 14) | ||
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | ||
Entity Central Index Key | 0000075488 | ||
The New York Stock Exchange | Common stock, no par value | |||
Title of 12(b) Security | Common stock, no par value | ||
Trading Symbol | PCG | ||
Security Exchange Name | NYSE | ||
The New York Stock Exchange | Equity Units | |||
Title of 12(b) Security | Equity Units | ||
Trading Symbol | PCGU | ||
Security Exchange Name | NYSE | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable | ||
Trading Symbol | PCG-PE | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% redeemable | ||
Trading Symbol | PCG-PD | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable | ||
Trading Symbol | PCG-PG | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable | ||
Trading Symbol | PCG-PH | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable | ||
Trading Symbol | PCG-PI | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable | ||
Trading Symbol | PCG-PA | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable | ||
Trading Symbol | PCG-PB | ||
Security Exchange Name | NYSEAMER | ||
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable | |||
Title of 12(b) Security | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable | ||
Trading Symbol | PCG-PC | ||
Security Exchange Name | NYSEAMER |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Revenues | |||
Total operating revenues | $ 21,680 | $ 20,642 | $ 18,469 |
Operating Expenses | |||
Operating and maintenance | 9,809 | 10,200 | 8,684 |
SB 901 securitization charges, net | 608 | 0 | 0 |
Wildfire-related claims, net of recoveries | 237 | 258 | 251 |
Wildfire Fund expense | 477 | 517 | 413 |
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,468 |
Total operating expenses | 19,843 | 18,759 | 16,714 |
Operating Income | 1,837 | 1,883 | 1,755 |
Interest income | 162 | 20 | 39 |
Interest expense | (1,917) | (1,601) | (1,260) |
Other income, net | 394 | 457 | 483 |
Reorganization items, net | 0 | (11) | (1,959) |
Income Before Income Taxes | 476 | 748 | (942) |
Income tax provision (benefit) | (1,338) | 836 | 362 |
Net Income (Loss) | 1,814 | (88) | (1,304) |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Income (Loss) Attributable to Common Shareholders | $ 1,800 | $ (102) | $ (1,318) |
Weighted Average Common Shares Outstanding, Basic (in shares) | 1,987 | 1,985 | 1,257 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 2,132 | 1,985 | 1,257 |
Net Income (Loss) Per Common Share, Basic (in dollars per share) | $ 0.91 | $ (0.05) | $ (1.05) |
Net Income (Loss) Per Common Share, Diluted (in dollars per share) | $ 0.84 | $ (0.05) | $ (1.05) |
Electric | |||
Operating Revenues | |||
Total operating revenues | $ 15,060 | $ 15,131 | $ 13,858 |
Operating Expenses | |||
Cost of electricity and natural gas | 2,756 | 3,232 | 3,116 |
Natural gas | |||
Operating Revenues | |||
Total operating revenues | 6,620 | 5,511 | 4,611 |
Operating Expenses | |||
Cost of electricity and natural gas | $ 2,100 | $ 1,149 | $ 782 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income (Loss) | $ 1,814 | $ (88) | $ (1,304) |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates) | 21 | 7 | (17) |
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively) | (6) | 0 | 0 |
Total other comprehensive income (loss) | 15 | 7 | (17) |
Comprehensive Income (Loss) | 1,829 | (81) | (1,321) |
Preferred stock dividend requirement of subsidiary | 14 | 14 | 14 |
Comprehensive Income (Loss) Attributable to Common Shareholders | $ 1,815 | $ (95) | $ (1,335) |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Statement of Comprehensive Income [Abstract] | |||
Pension and other postretirement benefit plans obligations, tax | $ 8 | $ 3 | $ 7 |
Net unrealized losses on available for sale securities, tax | $ 3 | $ 0 | $ 0 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Current Assets | ||
Cash and cash equivalents | $ 734 | $ 291 |
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | 213 | 16 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Regulatory balancing accounts | 3,264 | 2,999 |
Other | 1,624 | 1,784 |
Regulatory assets | 296 | 496 |
Inventories | ||
Gas stored underground and fuel oil | 91 | 44 |
Materials and supplies | 751 | 552 |
Wildfire Fund asset | 460 | 461 |
Other | 1,433 | 882 |
Total current assets | 12,815 | 11,077 |
Property, Plant, and Equipment | ||
Electric | 74,772 | 69,482 |
Gas | 28,226 | 25,979 |
Construction work in progress | 4,137 | 3,479 |
Financing lease and other | 19 | 20 |
Total property, plant, and equipment | 107,154 | 98,960 |
Accumulated depreciation | (30,946) | (29,134) |
Net property, plant, and equipment | 76,208 | 69,826 |
Other Noncurrent Assets | ||
Regulatory assets | 16,443 | 9,207 |
Customer credit trust | 745 | 0 |
Nuclear decommissioning trusts | 3,297 | 3,798 |
Operating lease right of use asset | 1,311 | 1,234 |
Wildfire Fund asset | 4,847 | 5,313 |
Income taxes receivable | 9 | 9 |
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates) | 2,969 | 2,863 |
Total other noncurrent assets | 29,621 | 22,424 |
TOTAL ASSETS | 118,644 | 103,327 |
Current Liabilities | ||
Short-term borrowings | 2,055 | 2,184 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,268 | 4,481 |
Accounts payable | ||
Trade creditors | 2,888 | 2,855 |
Regulatory balancing accounts | 1,658 | 1,121 |
Other | 778 | 679 |
Operating lease liabilities | 231 | 468 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 626 | 481 |
Wildfire-related claims | 1,912 | 2,722 |
Other | 3,372 | 2,436 |
Total current liabilities | 15,788 | 17,427 |
Noncurrent Liabilities | ||
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | 47,742 | 38,225 |
Regulatory liabilities | 17,630 | 11,999 |
Pension and other postretirement benefits | 231 | 860 |
Asset retirement obligations | 5,912 | 5,298 |
Deferred income taxes | 2,732 | 3,177 |
Operating lease liabilities | 1,243 | 810 |
Other | 4,291 | 4,308 |
Total noncurrent liabilities | 79,781 | 64,677 |
Shareholders’ Equity | ||
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates | 32,887 | 35,129 |
Treasury stock, at cost; 247,743,590 and 477,743,590 shares at respective dates | (2,517) | (4,854) |
Reinvested earnings | (7,542) | (9,284) |
Accumulated other comprehensive loss | (5) | (20) |
Total shareholders’ equity | 22,823 | 20,971 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 23,075 | 21,223 |
TOTAL LIABILITIES AND EQUITY | $ 118,644 | $ 103,327 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | $ 213 | $ 16 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,268 | 4,481 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 626 | 481 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | $ 47,742 | $ 38,225 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 3,600,000,000 | 3,600,000,000 |
Common stock, shares outstanding (in shares) | 1,987,784,948 | 1,985,400,540 |
Treasury stock, shares at cost (in shares) | 247,743,590 | 477,743,590 |
Variable Interest Entity, Primary Beneficiary | ||
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | $ 201 | $ 4 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,470 | 2,060 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,160 | 1,090 |
Net noncurrent accounts receivable | 17 | 187 |
Noncurrent allowance for doubtful accounts | 1 | 15 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 168 | 18 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 116 | 3 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | $ 10,310 | $ 1,820 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Operating Activities | |||
Net Income (Loss) | $ 1,814 | $ (88) | $ (1,304) |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,468 |
Bad debt expense | 143 | 154 | 150 |
Allowance for equity funds used during construction | (184) | (133) | (140) |
Deferred income taxes and tax credits, net | (452) | 1,783 | 1,097 |
Reorganization items, net | 0 | (73) | 1,458 |
Wildfire Fund expense | 477 | 517 | 413 |
Disallowed capital expenditures | 15 | 0 | 17 |
Other | 517 | 248 | 249 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (757) | (589) | (1,182) |
Wildfire-related insurance receivable | 453 | (723) | 1,564 |
Inventories | (246) | (32) | 6 |
Accounts payable | 627 | 117 | 58 |
Wildfire-related claims | (810) | 472 | (16,525) |
Other current assets and liabilities | 17 | 244 | (1,079) |
Regulatory assets, liabilities, and balancing accounts, net | (1,131) | (2,266) | (2,451) |
Liabilities subject to compromise | 0 | 0 | 413 |
Contributions to Wildfire fund | (193) | (193) | (5,200) |
Other noncurrent assets and liabilities | (425) | (579) | (142) |
Net cash provided by operating activities | 3,721 | 2,262 | (19,130) |
Cash Flows from Investing Activities | |||
Capital expenditures | (9,584) | (7,689) | (7,690) |
Proceeds from sale of SFGO | 0 | 749 | 0 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 3,316 | 1,678 | 1,518 |
Purchases of nuclear decommissioning trust investments | (3,208) | (1,702) | (1,590) |
Proceeds from sales and maturities of customer credit trust investments | 250 | 0 | 0 |
Purchases of customer credit trust investments | (1,022) | 0 | 0 |
Other | 34 | 59 | 14 |
Net cash used in investing activities | (10,214) | (6,905) | (7,748) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 0 | 0 | 500 |
Repayments of debtor-in-possession credit facility | 0 | 0 | (2,000) |
Debtor-in-possession credit facility debt issuance costs | 0 | 0 | (6) |
Bridge facility financing fees | 0 | 0 | (73) |
Borrowings under credit facilities | 10,130 | 9,730 | 8,554 |
Repayments under credit facilities | (9,750) | (9,976) | (3,949) |
Credit facilities financing fees | 0 | (9) | (22) |
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates | 0 | 300 | 1,448 |
Short-term debt matured | (300) | (1,450) | 0 |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $178 at respective dates | 4,271 | 4,624 | 13,497 |
Repayment of long-term debt | (5,968) | (87) | (764) |
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates | 312 | 0 | 0 |
Proceeds from sale of future revenue from transmission tower license sales, net of fees | 0 | 370 | 0 |
Exchanged debt financing fees | 0 | 0 | (103) |
Common stock issued | 0 | 0 | 7,582 |
Equity Units issued | 0 | 0 | 1,304 |
Other | 53 | (29) | (40) |
Net cash provided by financing activities | 7,133 | 4,323 | 25,928 |
Net change in cash, cash equivalents, and restricted cash | 640 | (320) | (950) |
Cash, cash equivalents, and restricted cash at January 1 | 307 | 627 | 1,577 |
Cash, cash equivalents, and restricted cash at December 31 | 947 | 307 | 627 |
Less: Restricted cash and restricted cash equivalents | (213) | (16) | (143) |
Cash and cash equivalents at December 31 | 734 | 291 | 484 |
Cash received (paid) for: | |||
Interest, net of amounts capitalized | (1,607) | (1,404) | (1,563) |
Income taxes, net | 0 | 99 | 0 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 1,174 | 1,311 | 515 |
Operating lease liabilities arising from obtaining ROU assets | 529 | 100 | 13 |
Common stock issued in satisfaction of liabilities | 0 | 0 | 8,276 |
Increase to PG&E Corporation common stock and treasury stock in connection with the Share Exchange and Tax Matters Agreement | (2,337) | 4,854 | 0 |
SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 7,464 | 0 | 0 |
Repayments of recovery bonds | (33) | 0 | 0 |
Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 972 | 850 | 0 |
Repayments of recovery bonds | $ (18) | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Financing Activities | |||
Issuance costs for short-term debt | $ 0 | $ 1 | $ 2 |
Premium, discount, and issuance costs on proceeds from long-term debt | 29 | 33 | 178 |
Performance based incentives earned | 38 | 0 | 0 |
SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Financing fees | 36 | 0 | 0 |
Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Financing fees | $ 11 | $ 10 | $ 0 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | PG&E ShareCo Common Stock | Total Shareholders' Equity | Common Stock | Treasury Stock | Reinvested Earnings | Accumulated Other Comprehensive Income (Loss) | Non- controlling Interest - Preferred Stock of Subsidiary | ||
Beginning balance (in shares) at Dec. 31, 2019 | 529,236,741 | |||||||||
Beginning balance at Dec. 31, 2019 | $ 5,388 | $ 5,136 | $ 13,038 | $ (7,892) | $ (10) | $ 252 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income (Loss) | (1,304) | (1,304) | (1,304) | |||||||
Other comprehensive income (loss) | (17) | (17) | (17) | |||||||
Common stock issued, net (in shares) | 1,455,441,932 | |||||||||
Common stock issued, net | 15,854 | 15,854 | $ 15,854 | |||||||
Equity units issued | 1,304 | 1,304 | 1,304 | |||||||
Stock-based compensation amortization | 28 | 28 | $ 28 | |||||||
Ending balance (in shares) at Dec. 31, 2020 | 1,984,678,673 | |||||||||
Ending balance at Dec. 31, 2020 | 21,253 | 21,001 | $ 30,224 | $ 0 | (9,196) | (27) | 252 | |||
Ending balance, treasury (in shares) at Dec. 31, 2020 | 0 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income (Loss) | (88) | (88) | (88) | |||||||
Other comprehensive income (loss) | 7 | 7 | 7 | |||||||
Common stock issued, net (in shares) | 477,743,590 | 721,867 | [1] | |||||||
Common stock issued, net | [1] | 4,854 | 4,854 | $ 4,854 | ||||||
Treasury stock acquired (in shares) | 477,743,590 | |||||||||
Treasury stock acquired | (4,854) | (4,854) | $ (4,854) | |||||||
Stock-based compensation amortization | $ 51 | 51 | $ 51 | |||||||
Ending balance (in shares) at Dec. 31, 2021 | 1,985,400,540 | 1,985,400,540 | ||||||||
Ending balance at Dec. 31, 2021 | $ 21,223 | 20,971 | $ 35,129 | $ (4,854) | (9,284) | (20) | 252 | |||
Ending balance, treasury (in shares) at Dec. 31, 2021 | 477,743,590 | 477,743,590 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||
Net Income (Loss) | $ 1,814 | 1,814 | 1,814 | |||||||
Other comprehensive income (loss) | 15 | 15 | 15 | |||||||
Common stock issued, net (in shares) | 2,384,408 | |||||||||
Common stock issued, net | (2,337) | (2,337) | $ (2,337) | |||||||
Treasury stock disposition (in shares) | (230,000,000) | |||||||||
Treasury stock disposition | 2,337 | 2,337 | $ 2,337 | |||||||
Stock-based compensation amortization | 95 | 95 | $ 95 | |||||||
Preferred stock dividend requirement of subsidiary in arrears | (59) | (59) | (59) | |||||||
Preferred stock dividend requirement of subsidiary | $ (13) | (13) | (13) | |||||||
Ending balance (in shares) at Dec. 31, 2022 | 1,987,784,948 | 1,987,784,948 | ||||||||
Ending balance at Dec. 31, 2022 | $ 23,075 | $ 22,823 | $ 32,887 | $ (2,517) | $ (7,542) | $ (5) | $ 252 | |||
Ending balance, treasury (in shares) at Dec. 31, 2022 | 247,743,590 | 247,743,590 | ||||||||
[1]Excludes 477,743,590 shares of common stock issued to ShareCo. For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2021 Form 10-K . |
CONSOLIDATED STATEMENTS OF IN_2
CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Revenues | |||
Total operating revenues | $ 21,680 | $ 20,642 | $ 18,469 |
Operating Expenses | |||
Operating and maintenance | 9,809 | 10,200 | 8,684 |
SB 901 securitization charges, net | 608 | 0 | 0 |
Wildfire-related claims, net of recoveries | 237 | 258 | 251 |
Wildfire Fund expense | 477 | 517 | 413 |
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,468 |
Total operating expenses | 19,843 | 18,759 | 16,714 |
Operating Income | 1,837 | 1,883 | 1,755 |
Interest income | 162 | 20 | 39 |
Interest expense | (1,917) | (1,601) | (1,260) |
Other income, net | 394 | 457 | 483 |
Reorganization items, net | 0 | (11) | (1,959) |
Income Before Income Taxes | 476 | 748 | (942) |
Income tax provision (benefit) | (1,338) | 836 | 362 |
Net Income (Loss) | 1,814 | (88) | (1,304) |
Preferred stock dividend requirement | 13 | ||
Income (Loss) Attributable to Common Shareholders | 1,800 | (102) | (1,318) |
Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | 21,680 | 20,642 | 18,469 |
Operating Expenses | |||
Operating and maintenance | 9,725 | 10,194 | 8,707 |
SB 901 securitization charges, net | 608 | 0 | 0 |
Wildfire-related claims, net of recoveries | 237 | 258 | 251 |
Wildfire Fund expense | 477 | 517 | 413 |
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,469 |
Total operating expenses | 19,759 | 18,753 | 16,738 |
Operating Income | 1,921 | 1,889 | 1,731 |
Interest income | 162 | 22 | 39 |
Interest expense | (1,658) | (1,373) | (1,111) |
Other income, net | 595 | 512 | 470 |
Reorganization items, net | 0 | (12) | (310) |
Income Before Income Taxes | 1,020 | 1,038 | 819 |
Income tax provision (benefit) | (1,206) | 900 | 408 |
Net Income (Loss) | 2,226 | 138 | 411 |
Preferred stock dividend requirement | 14 | 14 | 14 |
Income (Loss) Attributable to Common Shareholders | 2,212 | 124 | 397 |
Electric | |||
Operating Revenues | |||
Total operating revenues | 15,060 | 15,131 | 13,858 |
Operating Expenses | |||
Cost of electricity and natural gas | 2,756 | 3,232 | 3,116 |
Electric | Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | 15,060 | 15,131 | 13,858 |
Operating Expenses | |||
Cost of electricity and natural gas | 2,756 | 3,232 | 3,116 |
Natural gas | |||
Operating Revenues | |||
Total operating revenues | 6,620 | 5,511 | 4,611 |
Operating Expenses | |||
Cost of electricity and natural gas | 2,100 | 1,149 | 782 |
Natural gas | Pacific Gas & Electric Co (Utility) | |||
Operating Revenues | |||
Total operating revenues | 6,620 | 5,511 | 4,611 |
Operating Expenses | |||
Cost of electricity and natural gas | $ 2,100 | $ 1,149 | $ 782 |
CONSOLIDATED STATEMENTS OF CO_3
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Net Income (Loss) | $ 1,814 | $ (88) | $ (1,304) |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates) | 21 | 7 | (17) |
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively) | (6) | 0 | 0 |
Total other comprehensive income (loss) | 15 | 7 | (17) |
Comprehensive Income (Loss) | 1,829 | (81) | (1,321) |
Pacific Gas & Electric Co (Utility) | |||
Net Income (Loss) | 2,226 | 138 | 411 |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $2, $1, and $2, at respective dates) | 6 | (4) | (6) |
Net unrealized losses on available-for-sale securities (net of taxes of $3, $0, and $0, respectively) | (5) | 0 | 0 |
Total other comprehensive income (loss) | 1 | (4) | (6) |
Comprehensive Income (Loss) | $ 2,227 | $ 134 | $ 405 |
CONSOLIDATED STATEMENTS OF CO_4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension and other postretirement benefit plans obligations, tax | $ 8 | $ 3 | $ 7 |
Net unrealized losses on available for sale securities, tax | 3 | 0 | 0 |
Pacific Gas & Electric Co (Utility) | |||
Pension and other postretirement benefit plans obligations, tax | 2 | 1 | 2 |
Net unrealized losses on available for sale securities, tax | $ 3 | $ 0 | $ 0 |
CONSOLIDATED BALANCE SHEETS, UT
CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Current Assets | ||
Cash and cash equivalents | $ 734 | $ 291 |
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | 213 | 16 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Regulatory balancing accounts | 3,264 | 2,999 |
Other | 1,624 | 1,784 |
Regulatory assets | 296 | 496 |
Inventories | ||
Gas stored underground and fuel oil | 91 | 44 |
Materials and supplies | 751 | 552 |
Wildfire Fund asset | 460 | 461 |
Other | 1,433 | 882 |
Total current assets | 12,815 | 11,077 |
Property, Plant, and Equipment | ||
Electric | 74,772 | 69,482 |
Gas | 28,226 | 25,979 |
Construction work in progress | 4,137 | 3,479 |
Financing lease | 19 | 20 |
Total property, plant, and equipment | 107,154 | 98,960 |
Accumulated depreciation | (30,946) | (29,134) |
Net property, plant, and equipment | 76,208 | 69,826 |
Other Noncurrent Assets | ||
Regulatory assets | 16,443 | 9,207 |
Customer credit trust | 745 | 0 |
Nuclear decommissioning trusts | 3,297 | 3,798 |
Operating lease right of use asset | 1,311 | 1,234 |
Wildfire Fund asset | 4,847 | 5,313 |
Income taxes receivable | 9 | 9 |
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates) | 2,969 | 2,863 |
Total other noncurrent assets | 29,621 | 22,424 |
TOTAL ASSETS | 118,644 | 103,327 |
Current Liabilities | ||
Short-term borrowings | 2,055 | 2,184 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,268 | 4,481 |
Accounts payable | ||
Trade creditors | 2,888 | 2,855 |
Regulatory balancing accounts | 1,658 | 1,121 |
Other | 778 | 679 |
Operating lease liabilities | 231 | 468 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 626 | 481 |
Wildfire-related claims | 1,912 | 2,722 |
Other | 3,372 | 2,436 |
Total current liabilities | 15,788 | 17,427 |
Noncurrent Liabilities | ||
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | 47,742 | 38,225 |
Regulatory liabilities | 17,630 | 11,999 |
Pension and other postretirement benefits | 231 | 860 |
Asset retirement obligations | 5,912 | 5,298 |
Deferred income taxes | 2,732 | 3,177 |
Operating lease liabilities | 1,243 | 810 |
Other | 4,291 | 4,308 |
Total noncurrent liabilities | 79,781 | 64,677 |
Shareholders’ Equity | ||
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates | 32,887 | 35,129 |
Reinvested earnings | (7,542) | (9,284) |
Accumulated other comprehensive loss | (5) | (20) |
Total shareholders’ equity | 22,823 | 20,971 |
TOTAL LIABILITIES AND EQUITY | 118,644 | 103,327 |
Pacific Gas & Electric Co (Utility) | ||
Current Assets | ||
Cash and cash equivalents | 609 | 165 |
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | 213 | 16 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Regulatory balancing accounts | 3,264 | 2,999 |
Other | 1,633 | 1,932 |
Regulatory assets | 296 | 496 |
Inventories | ||
Gas stored underground and fuel oil | 91 | 44 |
Materials and supplies | 751 | 552 |
Wildfire Fund asset | 460 | 461 |
Other | 1,421 | 869 |
Total current assets | 12,687 | 11,086 |
Property, Plant, and Equipment | ||
Electric | 74,772 | 69,482 |
Gas | 28,226 | 25,979 |
Construction work in progress | 4,137 | 3,480 |
Financing lease | 18 | 18 |
Total property, plant, and equipment | 107,153 | 98,959 |
Accumulated depreciation | (30,946) | (29,131) |
Net property, plant, and equipment | 76,207 | 69,828 |
Other Noncurrent Assets | ||
Regulatory assets | 16,443 | 9,207 |
Customer credit trust | 745 | 0 |
Nuclear decommissioning trusts | 3,297 | 3,798 |
Operating lease right of use asset | 1,311 | 1,232 |
Wildfire Fund asset | 4,847 | 5,313 |
Income taxes receivable | 7 | 7 |
Other (includes noncurrent accounts receivable of $17 million and $187 million related to VIEs, net of noncurrent allowance for doubtful accounts of $1 million and $15 million at respective dates) | 2,834 | 2,706 |
Total other noncurrent assets | 29,484 | 22,263 |
TOTAL ASSETS | 118,378 | 103,177 |
Current Liabilities | ||
Short-term borrowings | 2,055 | 2,184 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,241 | 4,455 |
Accounts payable | ||
Trade creditors | 2,886 | 2,853 |
Regulatory balancing accounts | 1,658 | 1,121 |
Other | 747 | 648 |
Operating lease liabilities | 231 | 467 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 573 | 430 |
Wildfire-related claims | 1,912 | 2,722 |
Other | 3,067 | 2,430 |
Total current liabilities | 15,370 | 17,310 |
Noncurrent Liabilities | ||
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | 43,155 | 33,632 |
Regulatory liabilities | 17,630 | 11,999 |
Pension and other postretirement benefits | 160 | 764 |
Asset retirement obligations | 5,912 | 5,298 |
Deferred income taxes | 3,090 | 3,409 |
Operating lease liabilities | 1,243 | 810 |
Other | 4,334 | 4,345 |
Total noncurrent liabilities | 75,524 | 60,257 |
Shareholders’ Equity | ||
Preferred stock | 258 | 258 |
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates | 1,322 | 1,322 |
Additional paid-in capital | 29,280 | 28,286 |
Reinvested earnings | (3,368) | (4,247) |
Accumulated other comprehensive loss | (8) | (9) |
Total shareholders’ equity | 27,484 | 25,610 |
TOTAL LIABILITIES AND EQUITY | $ 118,378 | $ 103,177 |
CONSOLIDATED BALANCE SHEETS (_2
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | $ 213 | $ 16 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,268 | 4,481 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 626 | 481 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | $ 47,742 | $ 38,225 |
Common stock, par value (in dollars per share) | $ 0 | $ 0 |
Common stock, shares authorized (in shares) | 3,600,000,000 | 3,600,000,000 |
Common stock, shares outstanding (in shares) | 1,987,784,948 | 1,985,400,540 |
Pacific Gas & Electric Co (Utility) | ||
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | $ 213 | $ 16 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,645 | 2,345 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,304 | 1,207 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,241 | 4,455 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 573 | 430 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | $ 43,155 | $ 33,632 |
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 |
Variable Interest Entity, Primary Beneficiary | ||
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | $ 201 | $ 4 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,470 | 2,060 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,160 | 1,090 |
Net noncurrent accounts receivable | 17 | 187 |
Noncurrent allowance for doubtful accounts | 1 | 15 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 168 | 18 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 116 | 3 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | 10,310 | 1,820 |
Variable Interest Entity, Primary Beneficiary | Pacific Gas & Electric Co (Utility) | ||
Restricted cash (includes $201 million and $4 million related to VIEs at respective dates) | 201 | 4 |
Allowance for doubtful accounts | 166 | 171 |
Customers (net of allowance for doubtful accounts of $166 million and $171 million at respective dates) (includes $2.47 billion and $2.06 billion related to VIEs, net of allowance for doubtful accounts of $166 million and $171 million at respective dates) | 2,470 | 2,060 |
Accrued unbilled revenue (includes $1.16 billion and $1.09 billion related to VIEs at respective dates) | 1,160 | 1,090 |
Net noncurrent accounts receivable | 17 | 187 |
Noncurrent allowance for doubtful accounts | 1 | 15 |
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 168 | 18 |
Interest payable (includes $116 million and $3 million related to VIEs at respective dates) | 116 | 3 |
Long-term debt (includes $10.31 billion and $1.82 billion related to VIEs at respective dates) | $ 10,310 | $ 1,820 |
CONSOLIDATED STATEMENTS OF CA_3
CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Operating Activities | |||
Net Income (Loss) | $ 1,814 | $ (88) | $ (1,304) |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,468 |
Bad debt expense | 143 | 154 | 150 |
Allowance for equity funds used during construction | (184) | (133) | (140) |
Deferred income taxes and tax credits, net | (452) | 1,783 | 1,097 |
Reorganization items, net | 0 | (73) | 1,458 |
Wildfire Fund expense | 477 | 517 | 413 |
Disallowed capital expenditures | 15 | 0 | 17 |
Other | 517 | 248 | 249 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (757) | (589) | (1,182) |
Wildfire-related insurance receivable | 453 | (723) | 1,564 |
Inventories | (246) | (32) | 6 |
Accounts payable | 627 | 117 | 58 |
Wildfire-related claims | (810) | 472 | (16,525) |
Other current assets and liabilities | 17 | 244 | (1,079) |
Regulatory assets, liabilities, and balancing accounts, net | (1,131) | (2,266) | (2,451) |
Liabilities subject to compromise | 0 | 0 | 413 |
Contributions to Wildfire fund | (193) | (193) | (5,200) |
Other noncurrent assets and liabilities | (425) | (579) | (142) |
Net cash provided by operating activities | 3,721 | 2,262 | (19,130) |
Cash Flows from Investing Activities | |||
Capital expenditures | (9,584) | (7,689) | (7,690) |
Proceeds from sale of SFGO | 0 | 749 | 0 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 3,316 | 1,678 | 1,518 |
Purchases of nuclear decommissioning trust investments | (3,208) | (1,702) | (1,590) |
Proceeds from sales and maturities of customer credit trust investments | 250 | 0 | 0 |
Purchases of customer credit trust investments | (1,022) | 0 | 0 |
Other | 34 | 59 | 14 |
Net cash used in investing activities | (10,214) | (6,905) | (7,748) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 0 | 0 | 500 |
Repayments of debtor-in-possession credit facility | 0 | 0 | (2,000) |
Debtor-in-possession credit facility debt issuance costs | 0 | 0 | (6) |
Bridge facility financing fees | 0 | 0 | (73) |
Borrowings under credit facilities | 10,130 | 9,730 | 8,554 |
Repayments under credit facilities | (9,750) | (9,976) | (3,949) |
Credit facilities financing fees | 0 | (9) | (22) |
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates | 0 | 300 | 1,448 |
Short-term debt matured | (300) | (1,450) | 0 |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $88 at respective dates | 4,271 | 4,624 | 13,497 |
Repayments of long-term debt | (5,968) | (87) | (764) |
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates | 312 | 0 | 0 |
Proceeds from sale of future revenue from transmission tower license sales, net of fees | 0 | 370 | 0 |
Exchanged debt financing fees | 0 | 0 | (103) |
Other | 53 | (29) | (40) |
Net cash provided by financing activities | 7,133 | 4,323 | 25,928 |
Net change in cash, cash equivalents, and restricted cash | 640 | (320) | (950) |
Cash, cash equivalents, and restricted cash at January 1 | 307 | 627 | 1,577 |
Cash, cash equivalents, and restricted cash at December 31 | 947 | 307 | 627 |
Less: Restricted cash and restricted cash equivalents | (213) | (16) | (143) |
Cash and cash equivalents at December 31 | 734 | 291 | 484 |
Supplemental disclosures of cash flow information | |||
Interest, net of amounts capitalized | (1,607) | (1,404) | (1,563) |
Income taxes, net | 0 | 99 | 0 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 1,174 | 1,311 | 515 |
Operating lease liabilities arising from obtaining ROU assets | 529 | 100 | 13 |
SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 7,464 | 0 | 0 |
Repayments of recovery bonds | (33) | 0 | 0 |
Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 972 | 850 | 0 |
Repayments of recovery bonds | (18) | 0 | 0 |
Pacific Gas & Electric Co (Utility) | |||
Cash Flows from Operating Activities | |||
Net Income (Loss) | 2,226 | 138 | 411 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, amortization, and decommissioning | 3,856 | 3,403 | 3,469 |
Bad debt expense | 143 | 154 | 150 |
Allowance for equity funds used during construction | (184) | (133) | (140) |
Deferred income taxes and tax credits, net | (319) | 1,846 | 1,141 |
Reorganization items, net | 0 | (41) | (90) |
Wildfire Fund expense | 477 | 517 | 413 |
Disallowed capital expenditures | 15 | 0 | 17 |
Other | 102 | 172 | 220 |
Effect of changes in operating assets and liabilities: | |||
Accounts receivable | (763) | (584) | (1,160) |
Wildfire-related insurance receivable | 453 | (723) | 1,564 |
Inventories | (246) | (32) | 6 |
Accounts payable | 627 | 44 | (24) |
Wildfire-related claims | (810) | 472 | (16,525) |
Other current assets and liabilities | 16 | 251 | (1,141) |
Regulatory assets, liabilities, and balancing accounts, net | (1,131) | (2,266) | (2,451) |
Liabilities subject to compromise | 0 | 0 | 401 |
Contributions to Wildfire fund | (193) | (193) | (5,200) |
Other noncurrent assets and liabilities | (438) | (577) | (108) |
Net cash provided by operating activities | 3,831 | 2,448 | (19,047) |
Cash Flows from Investing Activities | |||
Capital expenditures | (9,584) | (7,689) | (7,690) |
Proceeds from sale of SFGO | 0 | 749 | 0 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 3,316 | 1,678 | 1,518 |
Purchases of nuclear decommissioning trust investments | (3,208) | (1,702) | (1,590) |
Proceeds from sales and maturities of customer credit trust investments | 250 | 0 | 0 |
Purchases of customer credit trust investments | (1,022) | 0 | 0 |
Proceeds from (repayments of) intercompany note to PG&E Corporation | 145 | (145) | 0 |
Other | 34 | 59 | 14 |
Net cash used in investing activities | (10,069) | (7,050) | (7,748) |
Cash Flows from Financing Activities | |||
Proceeds from debtor-in-possession credit facility | 0 | 0 | 500 |
Repayments of debtor-in-possession credit facility | 0 | 0 | (2,000) |
Debtor-in-possession credit facility debt issuance costs | 0 | 0 | (6) |
Bridge facility financing fees | 0 | 0 | (33) |
Borrowings under credit facilities | 10,130 | 9,730 | 8,554 |
Repayments under credit facilities | (9,750) | (9,976) | (3,949) |
Credit facilities financing fees | 0 | (9) | (22) |
Short-term debt financing, net of issuance costs of $0, $1, and $2 at respective dates | 0 | 300 | 1,448 |
Short-term debt matured | (300) | (1,450) | 0 |
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $29, $33, and $88 at respective dates | 4,271 | 4,624 | 8,837 |
Repayments of long-term debt | (5,941) | (59) | (100) |
Proceeds from DWR loan, net of performance based incentives earned of $38, $0, and $0 at respective dates | 312 | 0 | 0 |
Proceeds from sale of future revenue from transmission tower license sales, net of fees | 0 | 370 | 0 |
Exchanged debt financing fees | 0 | 0 | (103) |
Preferred stock dividends paid | (70) | 0 | 0 |
Common stock dividends paid | (1,275) | 0 | 0 |
Equity contribution from PG&E Corporation | 994 | 0 | 12,986 |
Other | 123 | (1) | (42) |
Net cash provided by financing activities | 6,879 | 4,379 | 26,070 |
Net change in cash, cash equivalents, and restricted cash | 641 | (223) | (725) |
Cash, cash equivalents, and restricted cash at January 1 | 181 | 404 | 1,129 |
Cash, cash equivalents, and restricted cash at December 31 | 822 | 181 | 404 |
Less: Restricted cash and restricted cash equivalents | (213) | (16) | (143) |
Cash and cash equivalents at December 31 | 609 | 165 | 261 |
Supplemental disclosures of cash flow information | |||
Interest, net of amounts capitalized | (1,374) | (1,198) | (1,458) |
Income taxes, net | 0 | 99 | 0 |
Supplemental disclosures of noncash investing and financing activities | |||
Capital expenditures financed through accounts payable | 1,174 | 1,311 | 515 |
Operating lease liabilities arising from obtaining ROU assets | 529 | 100 | 13 |
Common stock equity infusion from PG&E Corporation used to satisfy liabilities | 0 | 0 | 6,750 |
Pacific Gas & Electric Co (Utility) | SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 7,464 | 0 | 0 |
Repayments of recovery bonds | (33) | 0 | 0 |
Pacific Gas & Electric Co (Utility) | Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Proceeds from issuance of recovery bonds | 972 | 850 | 0 |
Repayments of recovery bonds | $ (18) | $ 0 | $ 0 |
CONSOLIDATED STATEMENTS OF CA_4
CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Cash Flows from Financing Activities | |||
Issuance costs for short-term debt | $ 0 | $ 1 | $ 2 |
Premium, discount, and issuance costs on proceeds from long-term debt | 29 | 33 | 178 |
Performance based incentives earned | 38 | 0 | 0 |
SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Financing fees | 36 | 0 | 0 |
Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Financing fees | 11 | 10 | 0 |
Pacific Gas & Electric Co (Utility) | |||
Cash Flows from Financing Activities | |||
Issuance costs for short-term debt | 0 | 1 | 2 |
Premium, discount, and issuance costs on proceeds from long-term debt | 29 | 33 | 88 |
Performance based incentives earned | 38 | 0 | 0 |
Pacific Gas & Electric Co (Utility) | SB 901 Securitization | |||
Cash Flows from Financing Activities | |||
Financing fees | 36 | 0 | 0 |
Pacific Gas & Electric Co (Utility) | Series 2022-A Recovery Bonds | |||
Cash Flows from Financing Activities | |||
Financing fees | $ 11 | $ 10 | $ 0 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY, UTILITY - USD ($) $ in Millions | Total | Pacific Gas & Electric Co (Utility) | Total Shareholders' Equity | Total Shareholders' Equity 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) | Accumulated Other Comprehensive Income (Loss) | Accumulated Other Comprehensive Income (Loss) Pacific Gas & Electric Co (Utility) |
Beginning balance at Dec. 31, 2019 | $ 5,388 | $ 5,136 | $ 5,335 | $ 258 | $ 13,038 | $ 1,322 | $ 8,550 | $ (7,892) | $ (4,796) | $ (10) | $ 1 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||
Net Income (Loss) | (1,304) | $ 411 | (1,304) | 411 | (1,304) | 411 | ||||||
Other comprehensive income (loss) | (17) | (6) | (17) | (6) | (17) | (6) | ||||||
Equity contribution | 19,736 | 19,736 | ||||||||||
Ending balance at Dec. 31, 2020 | 21,253 | 21,001 | 25,476 | 258 | 30,224 | 1,322 | 28,286 | (9,196) | (4,385) | (27) | (5) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||
Net Income (Loss) | (88) | 138 | (88) | 138 | (88) | 138 | ||||||
Other comprehensive income (loss) | 7 | (4) | 7 | (4) | 7 | (4) | ||||||
Ending balance at Dec. 31, 2021 | 21,223 | 20,971 | 25,610 | 258 | 35,129 | 1,322 | 28,286 | (9,284) | (4,247) | (20) | (9) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||
Net Income (Loss) | 1,814 | 2,226 | 1,814 | 2,226 | 1,814 | 2,226 | ||||||
Other comprehensive income (loss) | 15 | 1 | 15 | 1 | 15 | 1 | ||||||
Equity contribution | 994 | 994 | ||||||||||
Preferred stock dividend requirement of subsidiary in arrears | (59) | (59) | (59) | (59) | (59) | |||||||
Preferred stock dividend requirement | $ (11) | (13) | (13) | |||||||||
Common stock dividend | (1,275) | (1,275) | ||||||||||
Ending balance at Dec. 31, 2022 | $ 23,075 | $ 22,823 | $ 27,484 | $ 258 | $ 32,887 | $ 1,322 | $ 29,280 | $ (7,542) | $ (3,368) | $ (5) | $ (8) |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2022 | |
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, wildfire-related 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. |
BANKRUPTCY FILING
BANKRUPTCY FILING | 12 Months Ended |
Dec. 31, 2022 | |
Reorganizations [Abstract] | |
BANKRUPTCY FILING | BANKRUPTCY FILING Chapter 11 Proceedings On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Emergence 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. On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Emergence Date of July 1, 2020. Certain parties filed notices of appeal with respect to the Confirmation Order, including the Ad Hoc Committee of Holders of Trade Claims (the “Trade Committee”). The Trade Committee appealed the Confirmation Order’s holding, which awarded post-petition interest on general unsecured claims at the federal judgment rate of 2.59%. The Trade Committee is seeking for its members to receive post-petition interest at the rates specified under their contracts or the rate established under California state law, which is 10%. The Bankruptcy Court and the federal district court held that the Trade Committee’s members are entitled to post-petition interest at the federal judgment rate. On June 8, 2021, the Trade Committee appealed the federal district court decision to the Ninth Circuit Court of Appeals. On August 29, 2022, a three-judge panel of the Ninth Circuit Court of Appeals reversed the federal district court decision 2-1. On September 12, 2022, the Utility filed a petition for en banc review, which was denied on October 5, 2022. On February 2, 2023, the Utility filed a petition for a writ of certiorari to the Supreme Court of the United States. PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the post-petition interest matter, but the amount of that loss is not reasonably estimable at this time. If the Ninth Circuit Court of Appeals decision is not reversed, then the matter would be remanded to the Bankruptcy Court to evaluate the rate of interest for each individual contract, the conditions under which the contract rate applies, and whether payment of interest under state law would be warranted for each contract and claimant. These proceedings therefore will require extensive discovery and motion practice before the Bankruptcy Court with respect to each of these claims on a variety of contractual issues and equitable considerations. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings or any further appeals. 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. Unresolved Chapter 11 Claims PG&E Corporation and the Utility have received over 100,000 proofs of claim since January 29, 2019, of which approximately 80,000 were channeled to a trust for the benefit of holders of certain subrogation claims (the “Subrogation Wildfire Trust”) and the 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, 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. Amounts expected to be allowed are reflected as current liabilities in the Consolidated Balance Sheets. 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 Emergence Date, including claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”). In addition, Subordinated Debt Claims and HoldCo Rescission or Damage Claims (each as defined in Note 15 below) continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 15 under the heading “Securities Class Action Litigation.” |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
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 through 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. 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, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. 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 GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. 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 Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility 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: Year Ended December 31, (in millions) 2022 2021 Electric Revenue from contracts with customers Residential $ 6,130 $ 6,089 Commercial 5,416 5,042 Industrial 1,626 1,493 Agricultural 1,830 1,565 Public street and highway lighting 77 73 Other, net (1) (247) (84) Total revenue from contracts with customers - electric 14,832 14,178 Regulatory balancing accounts (2) 228 953 Total electric operating revenue $ 15,060 $ 15,131 Natural gas Revenue from contracts with customers Residential $ 3,353 $ 2,759 Commercial 1,005 713 Transportation service only 1,534 1,346 Other, net (1) 163 140 Total revenue from contracts with customers - gas 6,055 4,958 Regulatory balancing accounts (2) 565 553 Total natural gas operating revenue 6,620 5,511 Total operating revenues $ 21,680 $ 20,642 (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. Financial Assets Measured at Amortized Cost – Credit Losses PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets. Trade Receivables Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses. As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022. PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively. Other Receivables and Available-For-Sale Debt Securities 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. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss. As of December 31, 2022, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial. 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. Inventories Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, 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. 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 estimated service lives of its property, plant, and equipment were as follows: Estimated Service Balance at December 31, (in millions, except estimated service lives) Lives (years) 2022 2021 Electricity generating facilities (1) 5 to 75 $ 11,781 $ 11,217 Electricity distribution facilities 10 to 70 41,061 37,723 Electricity transmission facilities 15 to 75 16,413 15,516 Natural gas distribution facilities 20 to 60 15,366 14,100 Natural gas transmission and storage facilities 5 to 66 9,859 9,067 Financing lease 18 18 Construction work in progress 4,137 3,480 General plant and other 5 to 50 8,518 7,838 Total property, plant, and equipment 107,153 98,959 Accumulated depreciation (30,946) (29,131) Net property, plant, and equipment (2) $ 76,207 $ 69,828 (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 16 below. (2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 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, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments. 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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020. 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 cost 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 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 $81 million and $184 million during 2022, $56 million and $133 million during 2021, and $35 million and $140 million during 2020. Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations: (in millions) 2022 2021 ARO liability at beginning of year $ 5,298 $ 6,412 Liabilities incurred 134 — Revision in estimated cash flows 325 (1,378) Accretion 213 287 Liabilities settled (58) (23) ARO liability at end of year $ 5,912 $ 5,298 PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 4 below. 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. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 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 through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals. The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020. The increase of $614 million in the 2022 ARO liability at December 31, 2022 as compared to December 31, 2021 is primarily due to the update of the ARO associated with the Diablo Canyon power plant as described above; the creation of a new liability for the permanently abandoned electric transmission lines in connection with the Kincade SED Settlement (as defined in Note 15); increases in the probability that the Utility will be responsible for decommissioning certain hydroelectric generation facilities; increases in the costs associated with retiring gas transmission pipelines; and increases in escalation factors. The increase is offset by increases in the credit-adjusted risk-free rate from 2021 to 2022. 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 through rates and are held in trusts until authorized for release by the CPUC. Government Assistance PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance . Assembly Bill 180 On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred. Senate Bill 846 On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances. DWR Loan Agreement On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE's Civil Nuclear Credit Program” below). Under the loan agreement, the DWR will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements. U.S. DOE’s Civil Nuclear Credit Program On November 17, 2022, the Utility was conditionally awarded a total of approximately $1.1 billion from the DOE related to Diablo Canyon (See “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on actual costs. The Utility will repay its loans outstanding under the DWR Loan Agreement with funding received from the DOE’s Civil Nuclear Credit Program. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense 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 VIEs Receivables Securitization Program The SPV was created in connection with the Receivables Securitization Program and 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, 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 pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. 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 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 below. AB 1054 Securitization PG&E Recovery Funding LLC 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 financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below. SB 901 Securitization PG&E Wildfire Recovery Funding LLC 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 financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property. PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below. 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 as of December 31, 2022, 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 or 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 as of December 31, 2022, it did not consolidate any of them. Contributions to the Wildfire Fund Established Pursuant to AB 1054 PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims f |
REGULATORY ASSETS, LIABILITIES,
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS | NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery (in millions) 2022 2021 Pension benefits (1) $ 120 $ 708 Indefinitely Environmental compliance costs 1,193 1,089 32 years Utility retained generation (2) 86 133 4 years Price risk management 177 216 17 years Catastrophic event memorandum account (3) 1,085 1,119 1 - 3 years Wildfire expense memorandum account (4) 439 347 TBD years Fire hazard prevention memorandum account (5) 79 75 1 - 3 years Fire risk mitigation memorandum account (6) 65 44 1 - 3 years Wildfire mitigation plan memorandum account (7) 756 424 1 - 3 years Deferred income taxes (8) 2,730 1,849 51 years Insurance premium costs (9) 99 207 2 - 4 years Wildfire mitigation balancing account (10) 327 273 1 - 3 years Vegetation management balancing account (11) 2,276 1,411 1 - 3 years COVID-19 pandemic protection memorandum accounts (12) 26 49 TBD years Microgrid memorandum account (13) 213 163 1 - 3 years Financing costs (14) 211 175 Various SB 901 securitization (15) 5,378 — 30 years AROs in excess of recoveries (16) 120 — Various Other 1,063 925 Various Total long-term regulatory assets $ 16,443 $ 9,207 (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, 2022 and 2021, $44 million and $49 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval. (4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. 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 primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. 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, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. 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 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, 2022 . Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval. (12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval. (13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval. (14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date. (15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below. (16) 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 asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods. 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 Current Regulatory Liabilities At December 31, 2022 and 2021, the Utility had current regulatory liabilities of $1.12 billion and $698 million, respectively. At December 31, 2022, current regulatory liabilities consisted primarily of unrealized gains associated with the change in fair value of price risk management instruments that meet the definition of a derivative. An increase in natural gas prices has affected both the Utility’s gas and electric price risk management instruments, resulting in a deferral of $604 million. For more information, see Note 11 below. Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets. Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2022 2021 Cost of removal obligations (1) $ 7,773 $ 7,306 Recoveries in excess of AROs (2) — 388 Public purpose programs (3) 1,062 946 Employee benefit plans (4) 904 1,229 Transmission tower wireless licenses (5) 430 446 SFGO sale (6) 264 343 SB 901 securitization (7) 5,800 — Other 1,397 1,341 Total long-term regulatory liabilities $ 17,630 $ 11,999 (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 held 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 12 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. (5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers. (6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022. (7) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization since inception, and is expected to increase as additional qualifying amounts are recognized, including when the Fire Victim Trust sells additional shares. PG&E Corporation will continue to separately recognize tax benefits within income tax expense on the income statement. See Note 6 below. 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 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: Receivable (in millions) 2022 2021 Electric distribution (1) $ 448 $ — Gas distribution and transmission (2) 72 — Energy procurement (3) 684 310 Public purpose programs (4) 358 321 Fire hazard prevention memorandum account (5) — 50 Fire risk mitigation memorandum account (6) — 14 Wildfire mitigation plan memorandum account (7) — 67 Wildfire mitigation balancing account (8) 2 91 General rate case memorandum accounts (9) 3 468 Vegetation management balancing account (10) 137 127 Insurance premium costs (11) 602 605 Wildfire expense memorandum account (12) — 440 Residential uncollectibles balancing accounts (13) 126 127 Catastrophic event memorandum account 144 — Other 688 379 Total regulatory balancing accounts receivable $ 3,264 $ 2,999 Payable (in millions) 2022 2021 Electric distribution (1) $ — $ 121 Electric transmission (14) 228 24 Gas distribution and transmission (2) 66 83 Energy procurement (3) 428 211 Public purpose programs (4) 272 259 Nuclear decommissioning adjustment mechanism (15) 8 137 SFGO sale 152 21 Other 504 265 Total regulatory balancing accounts payable $ 1,658 $ 1,121 (1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings. (2) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings. (3) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. (4) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. (5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery. (9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC. (10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery. (11) 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, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets. (12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022. (13) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. (14) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. (15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
DEBT | DEBT 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, 2022: (in millions) Termination Maximum Facility Limit Loans Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility June 2027 $ 4,400 (1) $ (1,930) $ (998) $ 1,472 Utility receivables securitization program (2) September 2024 1,389 (3) (1,184) — 205 (3) PG&E Corporation revolving credit facility June 2025 500 — — 500 Total credit facilities $ 6,289 $ (3,114) $ (998) $ 2,177 (1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit. (2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above. (3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. Utility On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility. On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility. On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding. On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding. On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022. On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment. On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). PG&E Corporation On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future 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. On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid. On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation). Intercompany Note Payable On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full. AB 1054 AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction. The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction. On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”). Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order. For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above. Long-Term Debt Issuances and Redemptions Utility On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes. On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement . The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: Balance at (in millions) Contractual Interest Rates December 31, 2022 December 31, 2021 PG&E Corporation Term Loan - Stated Maturity: 2025 variable rate (1) $ 2,681 $ 2,709 Senior Secured Notes due 2028 5.00% 1,000 1,000 Senior Secured Notes due 2030 5.25% 1,000 1,000 Less: current portion, net of unamortized discount and debt issuance costs (28) (26) Unamortized discount/premium and debt issuance costs, net (66) (90) Total PG&E Corporation Long-Term Debt 4,587 4,593 Utility First Mortgage Bonds - Stated Maturity: 2022 variable rate (2) — 500 2022 1.75% — 2,500 2023 1.70% - 4.25% 2,075 3,575 2024 3.25% - 3.75% 1,800 800 2025 3.45% - 4.95% 1,925 1,475 2026 2.95% - 3.15% 2,551 2,551 2027 2.10% - 5.45% 3,000 2,550 2028 3.00% - 4.65% 1,975 1,975 2029 4.20% 400 — 2030 4.55% 3,100 3,100 2031 2.50% - 3.25% 3,000 3,000 2032 4.40% - 5.90% 1,050 — 2040 3.30% - 4.50% 2,951 2,951 2041 4.20% - 4.50% 700 700 2042 3.75% - 4.45% 750 750 2043 4.60% 375 375 2044 4.75% 675 675 2045 4.30% 600 600 2046 4.00% - 4.25% 1,050 1,050 2047 3.95% 850 850 2050 3.50% - 4.95% 5,025 5,025 2052 5.25% 550 — Less: current portion, net of unamortized discount and debt issuance costs (2,072) (2,996) Unamortized discount, premium and debt issuance costs, net (195) (190) Total Utility First Mortgage Bonds 32,135 31,816 Recovery Bonds (3) 9,292 860 Less: current portion (168) (18) DWR Loan (4) 312 — Credit Facilities Receivables securitization program - Stated Maturity: 2024 variable rate (5) 1,184 974 2-Year Term Loan - Stated Maturity: 2024 variable rate (6) 400 — 18-month Term Loan - Stated Maturity: 2023 variable rate (7) — 1,441 Less: current portion — (1,441) Total Utility Long-Term Debt 43,155 33,632 Total PG&E Corporation Consolidated Long-Term Debt $ 47,742 $ 38,225 (1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively. (2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%. (3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates. (4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance. (5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%. (6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%. (7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022. Contractual Repayment Schedule PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below: (in millions, except interest rates) 2023 2024 2025 2026 2027 Thereafter Total PG&E Corporation Average fixed interest rate — % — % — % — % — % 5.13 % 5.13 % Fixed rate obligations $ — $ — $ — $ — $ — $ 2,000 $ 2,000 Variable interest rate as of December 31, 2022 7.13 % 7.13 % 7.13 % — % — % — % 7.13 % Variable rate obligations $ 28 $ 28 $ 2,625 $ — $ — $ — $ 2,681 Utility (1) Average fixed interest rate 2.91 % 3.40 % 3.82 % 3.10 % 3.22 % 4.12 % 3.84 % Fixed rate obligations $ 2,075 $ 1,800 $ 1,925 $ 2,551 $ 3,000 $ 23,051 $ 34,402 Variable interest rate as of December 31, 2022 — % 5.54 % — % — % — % — % 5.54 % Variable rate obligations $ — $ 1,584 $ — $ — $ — $ — $ 1,584 Recovery Bonds (2) AB 1054 obligations $ 38 $ 46 $ 48 $ 50 $ 51 $ 1,592 $ 1,825 SB 901 obligations $ 130 $ 129 $ 135 $ 141 $ 146 $ 6,786 $ 7,467 Total consolidated debt $ 2,271 $ 3,587 $ 4,733 $ 2,742 $ 3,197 $ 33,429 $ 49,959 (1) The balance excludes DWR loan, see Note 3 - Government Assistance. (2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6. 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 customers 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. Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches: Tranche Amount Interest Rate Final Maturity Date A-1 $ 540,000,000 3.594 % June 1, 2032 A-2 $ 540,000,000 4.263 % June 1, 2038 A-3 $ 360,000,000 4.377 % June 3, 2041 A-4 $ 1,260,000,000 4.451 % December 1, 2049 A-5 $ 900,000,000 4.674 % December 1, 2053 The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date. On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision. On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches: Tranche Amount Interest Rate Final Maturity Date B-1 $ 613,080,000 4.022 % June 1, 2033 B-2 $ 600,000,000 4.722 % June 1, 2039 B-3 $ 500,040,000 5.081 % June 3, 2043 B-4 $ 1,149,960,000 5.212 % December 1, 2049 B-5 $ 1,036,920,000 5.099 % June 1, 2054 The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 12). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022. Also pursuant to the CHT decision, upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (See Note 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes. The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities: SB 901 securitization regulatory asset (in millions) Regulatory asset balance at inception $ 5,500 Amortization (122) Balance at December 31, 2022 $ 5,378 SB 901 securitization regulatory liability (in millions) Regulatory liability balance at inception $ (5,540) Amortization 308 Additions (568) Balance at December 31, 2022 $ (5,800) |
SB 901 SECURITIZATION AND CUSTO
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST | DEBT 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, 2022: (in millions) Termination Maximum Facility Limit Loans Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility June 2027 $ 4,400 (1) $ (1,930) $ (998) $ 1,472 Utility receivables securitization program (2) September 2024 1,389 (3) (1,184) — 205 (3) PG&E Corporation revolving credit facility June 2025 500 — — 500 Total credit facilities $ 6,289 $ (3,114) $ (998) $ 2,177 (1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit. (2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above. (3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the time period. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program. Utility On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPMorgan Chase Bank, N.A. and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement had an initial maturity date of July 1, 2023, subject to two one-year extensions at the option of the Utility. On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4.0 billion, (ii) extend the maturity date of such agreement to June 22, 2026 (subject to two one-year extensions at the option of the Utility), and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility. On March 31, 2022, the Utility prepaid in full the remaining portion of the 18-month tranche loans pursuant to an existing term loan credit agreement (the “2020 Utility Term Loan Credit Agreement”), in a principal amount equal to $298 million. As a result of such prepayment, the 2020 Utility Term Loan Credit Agreement was terminated and is no longer outstanding. On April 4, 2022, the Utility entered into a term loan credit agreement (the “2022A Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $500 million (the “364-Day 2022A Tranche Loans”). On July 21, 2022, the 364-Day 2022A Tranche Loans were prepaid in full with a portion of the proceeds from issuance of the Series 2022-B Recovery Bonds. As a result of such prepayment, the 2022A Utility Term Loan Credit Agreement was terminated and is no longer outstanding. On April 20, 2022, the Utility entered into a term loan credit agreement (the “2022B Utility Term Loan Credit Agreement”), comprised of 364-day tranche loans in the aggregate principal amount of $125 million (the “364-Day 2022B Tranche Loans”) and two-year tranche loans in the aggregate principal amount of $400 million (the “2-Year 2022B Tranche Loans”). The 364-Day 2022B Tranche Loans have a maturity date of April 19, 2023 and the 2-Year 2022B Tranche Loans have a maturity date of April 19, 2024. The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%. The Utility borrowed the entire amount of the 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans on April 20, 2022. On April 20, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, add an uncommitted incremental facility which, subject to certain conditions precedent, allows the SPV to request an increase in the facility limit by an additional $500 million to an aggregate amount of $1.5 billion. On August 12, 2022, the SPV made such a request to increase the facility limit, and the facility limit was subsequently increased to $1.5 billion on August 22, 2022. On September 30, 2022, the Utility entered into an amendment to the Receivables Securitization Program to, among other things, (i) extend the scheduled termination date to September 30, 2024 and (ii) implement a seasonal facility limit. After giving effect to the amendment, the facility limit fluctuates between $1.0 billion and $1.5 billion based on the periods set forth in the amendment. On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). PG&E Corporation On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, (subject to two one-year extensions at the option of PG&E Corporation). Any future 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. On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 (subject to two one-year extensions at the option of PG&E Corporation) and (ii) modify both the interest rate pricing grid and commitment fee pricing grid. On October 4, 2022, PG&E Corporation further amended the Corporation Revolving Credit Agreement to, among other things, extend the maturity date of such agreement to June 22, 2025 (subject to a one-year extension at the option of PG&E Corporation). Intercompany Note Payable On August 11, 2021, PG&E Corporation borrowed $145 million from the Utility under an interest bearing 364-day intercompany note due August 10, 2022. On June 17, 2022, this loan was repaid in full. AB 1054 AB 1054 provides that certain capital expenditures may be financed using a structure that securitizes a dedicated customer charge. On March 11, 2022, the Utility filed an application with the CPUC seeking authorization for a second transaction to securitize up to $1.7 billion of fire risk mitigation capital expenditure amounts that have been or would be incurred by the Utility from 2019 through 2022. The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding. On May 4, 2022, the $350 million of capital expenditure amounts were removed because the CPUC extended the schedule in the 2020 WMCE proceeding such that a final decision approving such capital expenditure amounts in that proceeding was no longer expected prior to the issuance of a financing order authorizing the second AB 1054 securitization transaction. The final amount to be securitized would be based on actual recorded capital expenditures incurred by the Utility prior to the securitization transaction. On August 5, 2022, the CPUC issued a final decision approving the securitization of up to approximately $1.4 billion of fire risk mitigation capital expenditures, which was the amount requested in the application less the $350 million pending in the 2020 WMCE proceeding. The Utility securitized $975 million of these expenditures in 2022 and plans to securitize remaining expenditures in subsequent periods. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. The senior secured recovery bonds were issued in three tranches: (1) approximately $215 million with an interest rate of 5.045% due July 15, 2034, (2) approximately $200 million with an interest rate of 5.256% due January 15, 2040, and (3) approximately $568 million with an interest rate of 5.536% due July 15, 2049. The payment dates for the Series 2022-A Senior Secured Recovery Bonds are January 15 and July 15 of each year, commencing on July 15, 2023 and continuing until the final maturity date. PG&E Recovery Funding LLC and the Utility entered into certain agreements in connection with the issuance of the Series 2022-A Senior Secured Recovery Bonds, including (1) the Recovery Property Purchase and Sale Agreement, dated as of November 30, 2022 (“the Sale Agreement”), (2) the Recovery Property Servicing Agreement, dated as of November 30, 2022 (the “Servicing Agreement”), and the Administration Agreement, dated as of November 30, 2022 (the “Administration Agreement”). Pursuant to the agreements described above, the Utility sells rights and interests in the Recovery Property (as defined in the Amended Articles) created pursuant to the Wildfire Financing Law and the Financing Order (as defined in the Amended Articles) to PG&E Recovery Funding LLC; the Utility carries out the functions pursuant to the Servicing Agreement to determine the Fixed Recovery Charges (as defined in the Amended Articles); and the Utility provides corporate management services to PG&E Recovery Funding LLC pursuant to the Administration Agreement. The Utility used the proceeds of the sale of the Recovery Property in accordance with the Wildfire Financing Law and the Financing Order. For more information on PG&E Recovery Funding LLC, see “Variable Interest Entities” in Note 3 above. Long-Term Debt Issuances and Redemptions Utility On February 18, 2022, the Utility completed the sale of (i) $1 billion aggregate principal amount of 3.25% First Mortgage Bonds due 2024, (ii) $400 million aggregate principal amount of 4.20% First Mortgage Bonds due 2029, (iii) $450 million aggregate principal amount of 4.40% First Mortgage Bonds due 2032 and (iv) $550 million aggregate principal amount of 5.25% First Mortgage Bonds due 2052. The proceeds were used for the prepayment of a portion of the 18-month tranche loans pursuant to the 2020 Utility Term Loan Credit Agreement, in an amount equal to $1.0 billion, and for general corporate purposes. On June 8, 2022, the Utility issued $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025, $450 million aggregate principal amount of 5.450% First Mortgage Bonds due June 15, 2027, and $600 million aggregate principal amount of 5.90% First Mortgage Bonds due June 15, 2032. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053. The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement . The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: Balance at (in millions) Contractual Interest Rates December 31, 2022 December 31, 2021 PG&E Corporation Term Loan - Stated Maturity: 2025 variable rate (1) $ 2,681 $ 2,709 Senior Secured Notes due 2028 5.00% 1,000 1,000 Senior Secured Notes due 2030 5.25% 1,000 1,000 Less: current portion, net of unamortized discount and debt issuance costs (28) (26) Unamortized discount/premium and debt issuance costs, net (66) (90) Total PG&E Corporation Long-Term Debt 4,587 4,593 Utility First Mortgage Bonds - Stated Maturity: 2022 variable rate (2) — 500 2022 1.75% — 2,500 2023 1.70% - 4.25% 2,075 3,575 2024 3.25% - 3.75% 1,800 800 2025 3.45% - 4.95% 1,925 1,475 2026 2.95% - 3.15% 2,551 2,551 2027 2.10% - 5.45% 3,000 2,550 2028 3.00% - 4.65% 1,975 1,975 2029 4.20% 400 — 2030 4.55% 3,100 3,100 2031 2.50% - 3.25% 3,000 3,000 2032 4.40% - 5.90% 1,050 — 2040 3.30% - 4.50% 2,951 2,951 2041 4.20% - 4.50% 700 700 2042 3.75% - 4.45% 750 750 2043 4.60% 375 375 2044 4.75% 675 675 2045 4.30% 600 600 2046 4.00% - 4.25% 1,050 1,050 2047 3.95% 850 850 2050 3.50% - 4.95% 5,025 5,025 2052 5.25% 550 — Less: current portion, net of unamortized discount and debt issuance costs (2,072) (2,996) Unamortized discount, premium and debt issuance costs, net (195) (190) Total Utility First Mortgage Bonds 32,135 31,816 Recovery Bonds (3) 9,292 860 Less: current portion (168) (18) DWR Loan (4) 312 — Credit Facilities Receivables securitization program - Stated Maturity: 2024 variable rate (5) 1,184 974 2-Year Term Loan - Stated Maturity: 2024 variable rate (6) 400 — 18-month Term Loan - Stated Maturity: 2023 variable rate (7) — 1,441 Less: current portion — (1,441) Total Utility Long-Term Debt 43,155 33,632 Total PG&E Corporation Consolidated Long-Term Debt $ 47,742 $ 38,225 (1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively. (2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%. (3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates. (4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance. (5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%. (6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%. (7) At December 31, 2021, LIBOR-based interest rate on the term loan was 2.38%. This loan was prepaid in full on March 31, 2022. Contractual Repayment Schedule PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below: (in millions, except interest rates) 2023 2024 2025 2026 2027 Thereafter Total PG&E Corporation Average fixed interest rate — % — % — % — % — % 5.13 % 5.13 % Fixed rate obligations $ — $ — $ — $ — $ — $ 2,000 $ 2,000 Variable interest rate as of December 31, 2022 7.13 % 7.13 % 7.13 % — % — % — % 7.13 % Variable rate obligations $ 28 $ 28 $ 2,625 $ — $ — $ — $ 2,681 Utility (1) Average fixed interest rate 2.91 % 3.40 % 3.82 % 3.10 % 3.22 % 4.12 % 3.84 % Fixed rate obligations $ 2,075 $ 1,800 $ 1,925 $ 2,551 $ 3,000 $ 23,051 $ 34,402 Variable interest rate as of December 31, 2022 — % 5.54 % — % — % — % — % 5.54 % Variable rate obligations $ — $ 1,584 $ — $ — $ — $ — $ 1,584 Recovery Bonds (2) AB 1054 obligations $ 38 $ 46 $ 48 $ 50 $ 51 $ 1,592 $ 1,825 SB 901 obligations $ 130 $ 129 $ 135 $ 141 $ 146 $ 6,786 $ 7,467 Total consolidated debt $ 2,271 $ 3,587 $ 4,733 $ 2,742 $ 3,197 $ 33,429 $ 49,959 (1) The balance excludes DWR loan, see Note 3 - Government Assistance. (2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6. 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 customers 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. Pursuant to SB 901, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to finance, using securitization, $7.5 billion of 2017 wildfire claims costs and create a corresponding customer credit trust that is designed to not impact the net amounts billed to customers. The proceeds of the securitization were used to repay certain debt that the Utility had initially issued for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. On April 23, 2021, the CPUC issued a decision finding that $7.5 billion of the Utility’s 2017 catastrophic wildfire costs and expenses are stress test costs that may be financed through the issuance of recovery bonds pursuant to Public Utilities Code sections 850 et seq. (“CHT Decision”). As requested, the decision authorized the Utility to establish a customer credit trust funded by PG&E Corporation’s shareholders that will provide a monthly credit to customers that is anticipated to equal the fixed recovery charges such that the securitization is designed to be rate neutral to customers. The decision adopts a transaction structure comprised of four elements: (1) an initial shareholder contribution to the customer credit trust of $2.0 billion, $1.0 billion of which was contributed in 2022 and $1.0 billion to be contributed in 2024; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; (3) a single CPUC review of the balance of the customer credit trust in 2040, with a single contingent supplemental shareholder contribution, if needed, up to $775 million in 2040; and (4) sharing with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust. On May 11, 2021, the CPUC issued a financing order authorizing the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance, using securitization, the $7.5 billion of claims associated with the 2017 Northern California wildfires. On February 28, 2022, the decision finding $7.5 billion of stress test costs eligible for securitization and the financing order authorizing the issuance of up to $7.5 billion of recovery bonds became final and non-appealable. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-A Recovery Bonds. The Series 2022-A Recovery Bonds were issued in five tranches: Tranche Amount Interest Rate Final Maturity Date A-1 $ 540,000,000 3.594 % June 1, 2032 A-2 $ 540,000,000 4.263 % June 1, 2038 A-3 $ 360,000,000 4.377 % June 3, 2041 A-4 $ 1,260,000,000 4.451 % December 1, 2049 A-5 $ 900,000,000 4.674 % December 1, 2053 The net proceeds were used to fund the redemption of all $500 million aggregate principal amount of the Utility’s Floating Rate First Mortgage Bonds due June 16, 2022 on May 16, 2022 and the redemption of all $2.5 billion aggregate principal amount of the Utility’s 1.75% First Mortgage Bonds due June 16, 2022 on May 16, 2022. The Utility used the remaining proceeds from the issuance of the Series 2022-A Recovery Bonds for the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The payment dates for the Series 2022-A Recovery Bonds are June 1 and December 1 of each year, commencing on December 1, 2022 and continuing until the final maturity date. On May 9, 2022, the Utility contributed $480 million to the customer credit trust. On July 19, 2022, the Utility contributed $520 million to the customer credit trust in full satisfaction of the first $1.0 billion as required by the CHT decision. On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued the Series 2022-B Recovery Bonds. The Series 2022-B Recovery Bonds were issued in five tranches: Tranche Amount Interest Rate Final Maturity Date B-1 $ 613,080,000 4.022 % June 1, 2033 B-2 $ 600,000,000 4.722 % June 1, 2039 B-3 $ 500,040,000 5.081 % June 3, 2043 B-4 $ 1,149,960,000 5.212 % December 1, 2049 B-5 $ 1,036,920,000 5.099 % June 1, 2054 The net proceeds were used to fund (1) the redemption of all $1.5 billion aggregate principal amount of the Utility’s 1.367% First Mortgage Bonds due March 10, 2023 on July 25, 2022, (2) the prepayment of all $500 million of loans outstanding under the 2022A Utility Term Loan Credit Agreement, and (3) the repayment of a portion of loans outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. The Utility also intends to use a portion of the remaining proceeds to fund the redemption of all $1.0 billion aggregate principal amount of the Utility’s 3.25% First Mortgage Bonds due 2024. The payment dates for the Series 2022-B Recovery Bonds are June 1 and December 1 of each year, commencing on June 1, 2023 and continuing until the final maturity date. Pursuant to the financing order, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by the SB 901 Recovery Property. The fixed recovery charge is designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. In the context of the CHT decision, which is intended to insulate customers from the fixed recovery charge, there is a customer credit which is designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds. The customer credit is funded by the customer credit trust (see Note 12). The fixed recovery charges and customer credits are presented on a net basis in Operating Revenues in the Consolidated Statements of Income and had no net impact on Operating Revenues for the year ended December 31, 2022. Also pursuant to the CHT decision, upon issuance of the Series 2022-A Recovery Bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, previously recognized within wildfire-related claims expense, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As the Fire Victim Trust sells the remaining shares it holds of PG&E Corporation common stock, the SB 901 securitization regulatory liability will increase, reflecting the recognition of additional income tax benefits, up to $7.59 billion as required in the CHT decision. As these tax benefits are monetized, they will be contributed to the customer credit trust. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Consolidated Statements of Income. During the year ended December 31, 2022, the Utility recorded SB 901 securitization charges, net, of $608 million for inception of the regulatory asset and liability pursuant to the CHT decision discussed above, as well as tax benefits realized within income tax expense in the current year related to the Fire Victim Trust’s sale of PG&E Corporation common stock (See Note 7 below) and amortization of the regulatory asset and liability in the Consolidated Statements of Income. SB 901 securitization charges are expected to increase in future periods, up to $2.09 billion, as the aforementioned tax benefits are recognized and recorded within deferred income taxes. The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities: SB 901 securitization regulatory asset (in millions) Regulatory asset balance at inception $ 5,500 Amortization (122) Balance at December 31, 2022 $ 5,378 SB 901 securitization regulatory liability (in millions) Regulatory liability balance at inception $ (5,540) Amortization 308 Additions (568) Balance at December 31, 2022 $ (5,800) |
COMMON STOCK AND SHARE-BASED CO
COMMON STOCK AND SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2022 | |
Common Stock And Share-Based Compensation [Abstract] | |
COMMON STOCK AND SHARE-BASED COMPENSATION | COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 1,987,784,948 shares of common stock outstanding at December 31, 2022, which excludes 247,743,590 shares of common stock owned by ShareCo, and 230,000,000 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2022. Equity Offerings During 2020, PG&E Corporation issued approximately 16 million PG&E Corporation equity units. The equity units represent the right of the unitholders to receive, on the settlement date, between 138 million and 168 million shares of PG&E Corporation common stock. The common stock received will be based on the value of PG&E Corporation common stock over a measurement period specified in the equity units purchase contracts and subject to certain adjustments as provided therein. The settlement date of the equity unit purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. At the Market Equity Distribution Program On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers,” respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at the market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreements”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement. On October 31, 2022, PG&E Corporation suspended the At the Market Equity Distribution Program until further notice. As of the suspension date, PG&E Corporation had not sold any shares pursuant to the Equity Distribution Agreement. Ownership Restrictions in PG&E Corporation’s Amended Articles Under Section 382 of the IRC, 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 DTAs 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). The 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 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation. On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes. Consequently, any shares owned by the Fire Victim Trust, along with any shares owned by the Utility directly, are effectively excluded from the total number of outstanding equity securities when calculating a person’s Percentage Stock Ownership (as defined in the Amended Articles) for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because ShareCo is a disregarded entity for income tax purposes. For example, although PG&E Corporation had 2,466,208,388 shares outstanding as of February 16, 2023, only 1,800,721,208 shares (that is, the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust, the Utility and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and taking into account the shares of PG&E Corporation common stock known to have been sold by the Fire Victim Trust as of February 16, 2023, a person’s effective Percentage Stock Ownership limitation for purposes of the Amended Articles as of February 16, 2023 was 3.46% of the outstanding shares. At various dates throughout 2022, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares. During the year ended December 31, 2022, the Fire Victim Trust’s sale of PG&E Corporation common stock in the aggregate amount of 230,000,000 shares resulted in an aggregate tax benefit of $870 million recorded in PG&E Corporation’s and the Utility’s Consolidated Financial Statements. As of February 16, 2023, to the knowledge of PG&E Corporation, the Fire Victim Trust had sold 290,000,000 shares of PG&E Corporation common stock in the aggregate. 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 IRC. 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 June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock and declared a common stock dividend of $425 million that was paid to PG&E Corporation on June 17, 2022. On September 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on September 16, 2022. On December 15, 2022, the Board of Directors of the Utility declared a common stock dividend of $425 million that was paid to PG&E Corporation on December 20, 2022. No dividend is payable until declared by the Board of Directors 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. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11. Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. Pursuant to the Confirmation Order, PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Emergence Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items as described in the Plan. PG&E Corporation is unable to predict when it will commence the payment of dividends on its common stock. Long-Term Incentive Plans The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) 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. A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 53,350,101 shares were available for future awards at December 31, 2022. The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2022: (in millions) 2022 2021 2020 Stock Options $ — $ — $ 3 Restricted stock units 60 35 15 Performance shares 55 21 17 Total compensation expense (pre-tax) $ 115 $ 56 $ 35 Total compensation expense (after-tax) $ 83 $ 40 $ 25 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, 2022, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation. The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. No stock options were granted in 2022 or 2021. 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, 2022. The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022: Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 2,195,834 $ 7.42 $ — Granted (1) — — — Exercised — — — Forfeited or expired (43,702) 10.23 — Outstanding at December 31 2,152,132 7.36 2.41 — Vested or expected to vest at December 31 2,152,132 7.36 2.41 — Exercisable at December 31 2,152,132 $ 7.36 2.41 $ — (1) Represents additional payout of existing stock option grants. Restricted Stock Units Restricted stock units 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 2022, 2021, and 2020 was $11.40, $11.01, and $9.25, respectively. The total fair value of restricted stock units that vested during 2022, 2021, and 2020 was $46 million, $19 million, and $31 million, respectively. The tax detriment from restricted stock units that vested in 2022 was $4 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, 2022, $74 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48 years. The following table summarizes restricted stock unit activity for 2022: Number of Weighted Average Grant- Nonvested at January 1 10,090,375 $ 11.00 Granted 5,850,945 11.40 Vested (4,175,008) 10.96 Forfeited (788,192) 11.18 Nonvested at December 31 10,978,120 $ 11.21 Performance Shares Performance shares generally vest three three Compensation expense attributable to performance shares is generally recognized ratably over the applicable three The following table summarizes activity for performance shares in 2022: Number of Weighted Average Grant- Nonvested at January 1 8,567,009 $ 9.64 Granted 3,105,604 13.44 Vested — — Forfeited (650,559) 10.15 Nonvested at December 31 11,022,054 $ 10.68 |
PREFERRED STOCK
PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022 and 2021, 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, respectively. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding. On December 31, 2022, 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, 2022, 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. On February 8, 2022, the Board of Directors of the Utility authorized the payment of all cumulative and unpaid dividends on the Utility’s preferred stock as of January 31, 2022 totaling $59.1 million, which was paid on May 13, 2022, to holders of record on April 29, 2022. In addition to the dividends paid in arrears, the Utility paid approximately $11 million of dividends on redeemable preferred stock during the year ended December 31, 2022. On December 15, 2022, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock totaling $3.5 million, which was paid on February 15, 2023, to holders of record on January 31, 2023. The Utility paid no dividends on preferred stock in 2021 or 2020. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
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 2022, 2021, and 2020. Year Ended December 31, (in millions, except per share amounts) 2022 2021 2020 Income (loss) available for common shareholders $ 1,800 $ (102) $ (1,318) Weighted average common shares outstanding, basic 1,987 1,985 1,257 Add incremental shares from assumed conversions: Employee share-based compensation 8 — — Equity Units 137 — — Weighted average common shares outstanding, diluted 2,132 1,985 1,257 Total earnings (loss) per common share, diluted $ 0.84 $ (0.05) $ (1.05) 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. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2022 | |
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 DTAs and liabilities. DTAs 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 technical merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2022 2021 2020 2022 2021 2020 Current: Federal $ (1) $ — $ (26) $ (1) $ — $ (26) State — 1 (34) — — (34) Deferred: Federal (943) 543 258 (852) 588 290 State (389) 296 171 (348) 316 185 Tax credits (5) (4) (7) (5) (4) (7) Income tax provision (benefit) $ (1,338) $ 836 $ 362 $ (1,206) $ 900 $ 408 The following tables describe net deferred income tax assets and liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2022 2021 2022 2021 Deferred income tax assets: Tax carryforwards $ 7,156 $ 5,628 $ 6,868 $ 5,425 Compensation 157 185 80 108 Greenhouse gas allowance 239 157 239 157 Wildfire-related claims (1) 1,489 1,723 1,489 1,723 Operating lease liability 368 346 368 346 Transmission tower wireless licenses 254 266 254 266 Other (2) 197 121 177 136 Total deferred income tax assets $ 9,860 $ 8,426 $ 9,475 $ 8,161 Deferred income tax liabilities: Property related basis differences 9,374 8,847 9,363 8,835 Regulatory balancing accounts 1,376 1,193 1,376 1,193 Debt financing costs 465 501 465 501 Operating lease right of use asset 368 346 368 346 Income tax regulatory asset (3) 764 517 764 517 Other (4) 245 199 230 178 Total deferred income tax liabilities $ 12,592 $ 11,603 $ 12,566 $ 11,570 Total net deferred income tax liabilities $ 2,732 $ 3,177 $ 3,091 $ 3,409 (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 in PG&E Corporation’s and the Utility’s service area over the past several years. (2) Amounts include benefits, state taxes, and customer advances for construction. (3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (4) Amount primarily includes an environmental reserve. The following table reconciles income tax expense at the federal statutory rate to the income tax provision: PG&E Corporation Utility Year Ended December 31, 2022 2021 2020 2022 2021 2020 Federal statutory income tax rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (75.8) 31.3 (15.3) (26.9) 24.1 19.1 Effect of regulatory treatment of fixed asset differences (2) (123.8) (71.5) 39.0 (49.2) (51.6) (44.9) Tax credits (3.2) (1.7) 1.5 (1.3) (1.2) (1.7) Fire Victim Trust (3) (160.9) 127.3 (44.9) (64.0) 91.9 51.7 Bankruptcy and emergence — — (37.6) — — 2.4 Other, net (4) 12.9 5.3 (2.1) 2.2 2.6 2.2 Effective tax rate (329.8) % 111.7 % (38.4) % (118.2) % 86.8 % 49.8 % (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 2022, 2021, and 2020, 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 tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020. (4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs. Unrecognized Tax Benefits The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2022 2021 2020 2022 2021 2020 Balance at beginning of year $ 498 $ 437 $ 420 $ 498 $ 437 $ 420 Reductions for tax position taken during a prior year (1) (23) (43) (1) (23) (43) Additions for tax position taken during the current year 73 85 60 73 85 60 Settlements — (1) — — (1) — Balance at end of year $ 570 $ 498 $ 437 $ 570 $ 498 $ 437 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2022 for PG&E Corporation and the Utility was $31 million. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress. 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, 2022, 2021, and 2020, 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. The Internal Revenue Service is auditing tax years 2015 through 2018. PG&E Corporation’s tax returns have been accepted through 2014 for California income tax purposes. Tax years 2015 and thereafter remain subject to examination by the State of California. The State of California is auditing tax years 2015 through 2019. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, 2022 Expiration Federal: Net operating loss carryforward - Pre-2018 $ 3,447 2031 - 2036 Net operating loss carryforward - Post-2017 23,170 N/A Tax credit carryforward 152 2029 - 2041 State: Net operating loss carryforward $ 25,169 2039 - 2041 Tax credit carryforward 126 Various 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 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. Half of the payment was paid in 2021, and the other half of the payment was paid in 2022. Under Section 382 of the IRC, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date (as defined in the Amended Articles) without approval by the Board of Directors of PG&E Corporation (the “Ownership Restrictions”). Due to the election to treat the Fire Victim Trust as a grantor trust for income tax purposes, the calculation of Percentage Stock Ownership (as defined in the Amended Articles) will effectively be based on a reduced number of shares outstanding, namely the total number of outstanding equity securities less the number of equity securities held by the Fire Victim Trust, the Utility, and ShareCo. 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 IRC. |
DERIVATIVES
DERIVATIVES | 12 Months Ended |
Dec. 31, 2022 | |
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 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 through 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 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: Contract Volume at Underlying Product Instruments December 31, 2022 December 31, 2021 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 171,212,813 173,361,635 Options 27,785,000 14,420,000 Electricity (MWh) Forwards, Futures and Swaps 10,814,728 10,283,639 Options 215,600 288,000 Congestion Revenue Rights (3) 205,743,505 239,857,610 (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 As of December 31, 2022, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 824 $ (170) $ 537 $ 1,191 Other noncurrent assets – other 306 — — 306 Current liabilities – other (238) 170 16 (52) Noncurrent liabilities – other (177) — — (177) Total commodity risk $ 715 $ — $ 553 $ 1,268 As of December 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 58 $ (9) $ 152 $ 201 Other noncurrent assets – other 169 — — 169 Current liabilities – other (53) 9 18 (26) Noncurrent liabilities – other (216) — — (216) Total commodity risk $ (42) $ — $ 170 $ 128 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2022 | |
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. Fair Value Measurements At December 31, 2022 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 658 $ — $ — $ — $ 658 Fixed-income securities — 49 — — 49 Nuclear decommissioning trusts Short-term investments 117 — — — 117 Global equity securities 1,845 — — — 1,845 Fixed-income securities 1,094 791 — — 1,885 Assets measured at NAV — — — — 25 Total nuclear decommissioning trusts (2) 3,056 791 — — 3,872 Customer credit trust Short-term investments 19 — — — 19 Global equity securities 218 — — — 218 Fixed-income securities 216 292 — — 508 Total customer credit trust 453 292 — — 745 Price risk management instruments (Note 11) Electricity — 94 432 40 566 Gas — 604 — 327 931 Total price risk management instruments — 698 432 367 1,497 Rabbi trusts Short-term investments 25 — — — 25 Global equity securities 5 — — — 5 Fixed-income securities — 69 — — 69 Life insurance contracts — 64 — — 64 Total rabbi trusts 30 133 — — 163 Long-term disability trust Short-term investments 10 — — — 10 Assets measured at NAV — — — — 133 Total long-term disability trust 10 — — — 143 TOTAL ASSETS $ 4,207 $ 1,963 $ 432 $ 367 $ 7,127 Liabilities: Price risk management instruments (Note 11) Electricity $ — $ 10 $ 233 $ (20) $ 223 Gas — 172 — (166) 6 TOTAL LIABILITIES $ — $ 182 $ 233 $ (186) $ 229 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $575 million primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 289 $ — $ — $ — $ 289 Nuclear decommissioning trusts Short-term investments 22 — — — 22 Global equity securities 2,504 — — — 2,504 Fixed-income securities 1,158 866 — — 2,024 Assets measured at NAV — — — — 31 Total nuclear decommissioning trusts (2) 3,684 866 — — 4,581 Price risk management instruments (Note 10) Electricity — 9 214 6 229 Gas — 4 — 137 141 Total price risk management instruments — 13 214 143 370 Rabbi trusts Fixed-income securities — 104 — — 104 Life insurance contracts — 76 — — 76 Total rabbi trusts — 180 — — 180 Long-term disability trust Short-term investments 6 — — — 6 Assets measured at NAV — — — — 132 Total long-term disability trust 6 — — — 138 TOTAL ASSETS $ 3,979 $ 1,059 $ 214 $ 143 $ 5,558 Liabilities: Price risk management instruments (Note 10) Electricity $ — $ 11 $ 248 $ (24) $ 235 Gas — 10 — (3) 7 TOTAL LIABILITIES $ — $ 21 $ 248 $ (27) $ 242 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $783 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, 2022 and 2021. 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, customer credit 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 classified as 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, credit 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 rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 11 above. Fair Value at (in millions) At December 31, 2022 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 305 $ 138 Market approach CRR auction prices $ (145.09) - 2,724.93 / 0.89 Power purchase agreements $ 127 $ 95 Discounted cash flow Forward prices $ (6.39) - 286.75 / 78.14 (1) Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) At December 31, 2021 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 188 $ 93 Market approach CRR auction prices $ (40.77) - 2,265.94 / 0.40 Power purchase agreements $ 26 $ 155 Discounted cash flow Forward prices $ (7.97) - 256.20 / 47.17 (1) Represents price per MWh. (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, 2022 and 2021, respectively: Price Risk Management Instruments (in millions) 2022 2021 Liability balance as of January 1 $ (34) $ (72) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 233 38 Asset (Liability) balance as of December 31 $ 199 $ (34) (1) The costs related to price risk management activities are recovered through 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 as of December 31, 2022 and December 31, 2021, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2022 At December 31, 2021 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation $ 4,355 $ 4,490 $ 4,619 $ 4,796 Utility 32,847 27,666 31,816 35,803 Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Total Total Fair As of December 31, 2022 Nuclear decommissioning trusts Short-term investments $ 117 $ — $ — $ 117 Global equity securities 413 1,468 (11) 1,870 Fixed-income securities 1,991 10 (116) 1,885 Total (1) $ 2,521 $ 1,478 $ (127) $ 3,872 As of December 31, 2021 Nuclear decommissioning trusts Short-term investments $ 22 $ — $ — $ 22 Global equity securities 479 2,066 (10) 2,535 Fixed-income securities 1,938 98 (12) 2,024 Total (1) $ 2,439 $ 2,164 $ (22) $ 4,581 (1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2022 Less than 1 year $ 42 1–5 years 624 5–10 years 400 More than 10 years 819 Total maturities of fixed-income securities $ 1,885 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2022 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 3,316 $ 1,678 $ 1,518 Gross realized gains on securities 2 286 159 Gross realized losses on securities (3) (19) (41) Customer Credit Trust The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Total Total Fair As of December 31, 2022 Customer credit trust Short-term investments $ 19 $ — $ — $ 19 Global equity securities 219 13 (14) 218 Fixed-income securities 516 — (8) 508 Total $ 754 $ 13 $ (22) $ 745 The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2022 Less than 1 year $ 79 1–5 years 123 5–10 years 120 More than 10 years 186 Total maturities of fixed-income securities $ 508 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2022 Proceeds from sales and maturities of customer credit trust investments $ 250 Gross realized gains on securities 10 Gross realized losses on securities (1) (41) (1) Includes $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2022. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2022 | |
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 IRC. 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 plan up to the amount it is authorized to recover through 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 2022 and 2021: Pension Plan (in millions) 2022 2021 Change in plan assets: Fair value of plan assets at beginning of year $ 21,895 $ 20,759 Actual return on plan assets (4,916) 1,693 Company contributions 339 335 Benefits and expenses paid (949) (892) Fair value of plan assets at end of year $ 16,369 $ 21,895 Change in benefit obligation: Benefit obligation at beginning of year $ 22,759 $ 23,172 Service cost for benefits earned 575 587 Interest cost 692 645 Actuarial gain (1) (6,471) (752) Plan amendments — — Benefits and expenses paid (947) (893) Benefit obligation at end of year (2) $ 16,608 $ 22,759 Funded Status: Current liability $ (8) $ (9) Noncurrent liability (231) (856) Net liability at end of year $ (239) $ (865) (1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions. (2) PG&E Corporation’s accumulated benefit obligation was $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively. Postretirement Benefits Other than Pensions (in millions) 2022 2021 Change in plan assets: Fair value of plan assets at beginning of year $ 3,102 $ 2,995 Actual return on plan assets (693) 193 Company contributions 26 10 Plan participant contribution 81 80 Benefits and expenses paid (180) (176) Fair value of plan assets at end of year $ 2,336 $ 3,102 Change in benefit obligation: Benefit obligation at beginning of year $ 1,766 $ 1,876 Service cost for benefits earned 62 63 Interest cost 53 51 Actuarial gain (1) (486) (152) Benefits and expenses paid (162) (156) Federal subsidy on benefits paid 3 4 Plan participant contributions 81 80 VSP related termination benefits (3) 22 — Benefit obligation at end of year $ 1,339 $ 1,766 Funded Status: (2) Noncurrent asset $ 997 $ 1,340 Noncurrent liability — (4) Net asset at end of year $ 997 $ 1,336 (1) The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes (2) At December 31, 2022 and 2021, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively. (3) Represents VSP-related credits to employee retirement health savings accounts. See Note 3 above. 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 costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows: Pension Plan (in millions) 2022 2021 2020 Service cost for benefits earned (1) $ 575 $ 587 $ 530 Interest cost 692 645 713 Expected return on plan assets (1,189) (1,046) (1,044) Amortization of prior service cost (4) (6) (6) Amortization of net actuarial loss 2 6 3 Net periodic benefit cost 76 186 196 Less: transfer to regulatory account (2) 254 147 136 Total expense recognized $ 330 $ 333 $ 332 (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 through future rates. Postretirement Benefits Other than Pensions (in millions) 2022 2021 2020 Service cost for benefits earned (1) $ 62 $ 63 $ 61 Interest cost 53 51 63 Expected return on plan assets (130) (137) (138) Amortization of prior service cost 7 14 14 Amortization of net actuarial loss (40) (33) (21) Special termination benefits 22 — — Net periodic benefit cost $ (26) $ (42) $ (21) (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. Pension Plan PBOP Plans December 31, December 31, 2022 2021 2020 2022 2021 2020 Discount rate 5.54 % 3.03 % 2.77 % 5.50 - 5.54% 2.97 - 3.04% 2.67 - 2.80% Rate of future compensation increases 3.80 % 3.80 % 3.80 % N/A N/A N/A Expected return on plan assets 6.10 % 5.50 % 5.10 % 3.70 - 7.30% 3.30 - 6.40% 3.10 - 6.10% Interest crediting rate for cash balance plan 4.19 % 1.95 % 1.95 % N/A N/A N/A The assumed health care cost trend rate as of December 31, 2022 was 6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 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 6.1% compares to a ten-year actual return of 5.8%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 848 Aa-grade non-callable bonds at December 31, 2022. 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 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 allocation between fixed income and equity 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: Pension Plan PBOP Plans 2023 2022 2021 2023 2022 2021 Global equity securities 26 % 30 % 30 % 28 % 26 % 36 % Absolute return 1 % 2 % 2 % 1 % 1 % 1 % Real assets 8 % 8 % 8 % 3 % 3 % 5 % Fixed-income securities 65 % 60 % 60 % 68 % 70 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. Fair Value Measurements The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2022 and 2021. Fair Value Measurements At December 31, 2022 2021 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 461 $ 126 $ — $ 587 $ 552 $ 255 $ — $ 807 Global equity securities 1,430 — — 1,430 2,074 424 — 2,498 Absolute Return — — — — — 1 — 1 Real assets 426 — — 426 632 — — 632 Fixed-income securities 1,946 6,086 8 8,040 2,729 7,388 27 10,144 Assets measured at NAV — — — 5,886 — — — 7,972 Total $ 4,263 $ 6,212 $ 8 $ 16,369 $ 5,987 $ 8,068 $ 27 $ 22,054 PBOP Plans: Short-term investments $ 26 $ — $ — $ 26 $ 31 $ — $ — $ 31 Global equity securities 83 — — 83 105 — — 105 Real assets 29 — — 29 34 — — 34 Fixed-income securities 406 702 1 1,109 776 875 1 1,652 Assets measured at NAV — — — 1,100 — — — 1,296 Total $ 544 $ 702 $ 1 $ 2,347 $ 946 $ 875 $ 1 $ 3,118 Total plan assets at fair value $ 18,716 $ 25,172 In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $11 million and $175 million at December 31, 2022 and 2021, 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 NAV 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, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities. Transfers Between Levels No material transfers between levels occurred in the years ended December 31, 2022 or 2021. 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, 2022 and 2021: (in millions) For the year ended December 31, 2022 Fixed-Income Balance at beginning of year $ 27 Actual return on plan assets: Relating to assets still held at the reporting date 1 Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 6 Settlements (26) Balance at end of year $ 8 (in millions) For the year ended December 31, 2021 Fixed-Income Balance at beginning of year $ 12 Actual return on plan assets: Relating to assets still held at the reporting date 6 Relating to assets sold during the period (7) Purchases, issuances, sales, and settlements: Purchases 22 Settlements (6) Balance at end of year $ 27 There were no material transfers out of Level 3 in 2022 or 2021. Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $339 million to the pension benefit plans and $26 million to the other benefit plans in 2022. 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 2022. The Utility’s pension benefits met all the funding requirements under the Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the pension plan in 2023. PG&E Corporation and the Utility did not request to make contributions to the other postretirement benefit plans in the 2023 GRC. Benefits Payments and Receipts As of December 31, 2022, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension PBOP Federal 2023 907 97 (4) 2024 996 98 (4) 2025 1028 100 (4) 2026 1057 94 (4) 2027 1,082 94 (4) Thereafter in the succeeding five years 5,702 475 (4) 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 IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provides 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 $144 million, $133 million, and $119 million in 2022, 2021, and 2020, 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. |
RELATED PARTY AGREEMENTS AND TR
RELATED PARTY AGREEMENTS AND TRANSACTIONS | 12 Months Ended |
Dec. 31, 2022 | |
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: Year Ended December 31, (in millions) 2022 2021 2020 Utility revenues from: Administrative services provided to PG&E Corporation $ 3 $ 3 $ 3 Utility expenses from: Administrative services received from PG&E Corporation $ 104 $ 82 $ 108 Utility employee benefit due to PG&E Corporation 85 39 34 At December 31, 2022 and 2021, the Utility had receivables of $33 million and $173 million, respectively, from PG&E Corporation included in Accounts receivable – other and Noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $46 million and $19 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets. |
WILDFIRE-RELATED CONTINGENCIES
WILDFIRE-RELATED CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
WILDFIRE-RELATED CONTINGENCIES | WILDFIRE-RELATED CONTINGENCIES Liability Overview PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. 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. Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), 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 courts or other governmental entities. PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints 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 relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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 through rates. 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. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. 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 July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire. On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation. On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022. In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022. On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire. Additionally, on July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022. On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect. 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 Cal Fire’s determination of the cause and 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 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance). PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 769 Accrued Losses 225 Payments (344) Balance at December 31, 2022 $ 650 The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, 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 area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged. On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo. On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding. On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred. 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. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to 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. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for August 14, 2023. In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect. 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 Cal Fire’s determination of the cause and 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. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance). PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 211 Accrued Losses 25 Payments (204) Balance at December 31, 2022 $ 32 The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2022, the Utility recorded an insurance receivable for $370 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $30 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa. 2021 Dixie Fire According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire. On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it. The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing. On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation. On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire. 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 Cal Fire’s determination of the cause and 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 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022. PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other 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 including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 1,150 Accrued Losses 25 Payments (44) Bala |
OTHER CONTINGENCIES AND COMMITM
OTHER CONTINGENCIES AND COMMITMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
OTHER CONTINGENCIES AND COMMITMENTS | WILDFIRE-RELATED CONTINGENCIES Liability Overview PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the best estimate or lower end of the range often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. 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. Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), 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 courts or other governmental entities. PG&E Corporation and the Utility are aware of numerous civil complaints related to the following wildfire events and expect that they may receive further such complaints. The complaints 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 relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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 through rates. 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. In addition to claims for property damage, business interruption, interest and attorneys’ fees under inverse condemnation, 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. 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 July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire. On April 6, 2021, the Sonoma County District Attorney’s Office (“the Sonoma D.A.”) filed a complaint charging the Utility with five felonies and 28 misdemeanors related to the 2019 Kincade fire. On January 28, 2022, the Sonoma D.A. filed the Kincade Amended Complaint, which replaced two felonies with five different felonies and dropped six misdemeanor counts. On April 8, 2022, the Utility and the Sonoma D.A. filed a civil stipulated judgment to resolve the criminal prosecution of the Utility in connection with the 2019 Kincade fire (the “Kincade Stipulation”) without the Utility admitting any liability. Subject to the terms and conditions of the Kincade Stipulation, the Utility will pay a total of $20.25 million, which will not be recoverable through rates. Pursuant to the Kincade Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving Sonoma County; (ii) take certain wildfire mitigation actions consistent with its WMP; and (iii) engage an independent compliance monitor for at least five years to monitor the Utility’s compliance with certain commitments under the Kincade Stipulation, including its commitments to carry out vegetation management and equipment inspections in Sonoma County consistent with its WMP. After the Kincade Stipulation was entered by the Sonoma County Superior Court, the Sonoma D.A. moved to dismiss the Kincade Amended Complaint with prejudice, and the court granted the motion on April 11, 2022. In the first quarter of 2022, PG&E Corporation and the Utility recorded $20.25 million within Other current liabilities and Other noncurrent liabilities in connection with the Kincade Stipulation. As of December 31, 2022, $5.45 million has been paid pursuant to the Kincade Stipulation. On July 14, 2022, the CPUC issued final approval of a settlement between the SED and the Utility (the “Kincade SED Settlement”). The Kincade SED Settlement resolves SED’s investigation into the 2019 Kincade fire and provides for the removal of approximately 70 transmission lines or portions of lines that are no longer in service and are de-energized but have not been removed as required by CPUC rules. The Kincade SED Settlement provides that the Utility (i) will pay $40 million to California’s General Fund; (ii) will remove permanently abandoned transmission lines over a ten-year period; and (iii) must incur $85 million of the costs of such work by December 31, 2024, for which it may not seek recovery. SED agreed to refrain from instituting enforcement proceedings against the Utility for not having removed the lines previously. The Kincade SED Settlement states that it does not constitute an admission by the Utility of violations of GOs or statutory requirements. In the third quarter of 2021, PG&E Corporation and the Utility recorded $40 million within Other current liabilities in connection with the Kincade SED Settlement. As of December 31, 2022, $20 million has been paid to California’s General Fund pursuant to the Kincade SED Settlement. For the $85 million of cost of removal that the Utility will not seek recovery, the Utility recorded such disallowances in the first quarter of 2022 upon identification of the facilities to be removed. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 113 complaints on behalf of at least 2,720 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court scheduled trial for November 7, 2022, which it vacated on October 11, 2022. In addition, on January 5, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $90 million for fire suppression and other costs incurred in connection with the 2019 Kincade fire. The Utility filed an answer to Cal Fire’s complaint on February 4, 2022. On April 28, 2022, subrogation plaintiffs filed a motion for summary adjudication of their inverse condemnation cause of action in the coordinated proceeding. The court scheduled a hearing on this summary adjudication motion for August 5, 2022, which it vacated on July 29, 2022. On October 26, 2022, PG&E Corporation and the Utility entered an agreement with substantially all of the insurance subrogation plaintiffs to resolve their claims arising from the 2019 Kincade fire. Additionally, on July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. The court scheduled a hearing on this summary adjudication motion for October 7, 2022, which it vacated on October 6, 2022. On October 11, 2022, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), which remains in effect. 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 Cal Fire’s determination of the cause and 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 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $800 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges during 2022 for potential losses in connection with the 2019 Kincade fire of $225 million, for an aggregate liability of $1.025 billion (before available insurance). PG&E Corporation’s and the Utility’s accrued estimated losses of $1.025 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 769 Accrued Losses 225 Payments (344) Balance at December 31, 2022 $ 650 The Utility has liability insurance coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. As of December 31, 2022, the Utility recorded an insurance receivable for the full amount of $430 million. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, at approximately 4:03 p.m. Pacific Time, 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 area of the Utility. According to a Cal Fire incident update dated October 16, 2020, 3:08 p.m. Pacific Time, the 2020 Zogg fire consumed 56,338 acres and resulted in four fatalities, one injury, 204 structures destroyed, and 27 structures damaged. On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo. On September 24, 2021, the Shasta County District Attorney’s Office charged the Utility with 11 felonies and 20 misdemeanors related to the 2020 Zogg fire, the 2020 Daniel fire, the 2020 Ponder fire, and the 2021 Woody fire. On September 24, 2021, PG&E Corporation and the Utility announced that they disputed the charges. They further announced that they would accept Cal Fire’s finding that a Utility electric line caused the 2020 Zogg fire, even though PG&E Corporation and the Utility did not have access to all of the evidence that Cal Fire gathered. On November 18, 2021, the Utility filed a demurrer to 10 of the 31 counts. On May 2, 2022, the Shasta County Superior Court overruled the demurrer. On June 9, 2022, the Utility entered a plea of not guilty to all of the charges. At the conclusion of the preliminary hearing conducted in January and February 2023, the court dismissed 20 of the 31 counts, including all charges related to the three smaller fires as well as all charges relating to air contamination. On February 3, 2023, the Shasta County District Attorney’s Office filed a superseding charging document, which charges the Utility with the 11 remaining counts. The court has set a trial date on those charges for June 6, 2023. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victims and is not offset by any compensation that the victims have received or may receive from their insurance carriers. If convicted of any of the charges, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorneys’ fees and interest), as well as non-monetary remedies such as oversight requirements. If convicted of any of the charges, the Utility currently believes that its total losses associated with the fire could materially exceed the accrued estimated liabilities that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses. The Utility is unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding. On October 25, 2022, the SED issued a proposed administrative enforcement order alleging that the Utility violated CPUC regulations and Public Utilities Code Section 451 in connection with the CPUC’s investigation of the 2020 Zogg fire. The proposed order recommends a penalty of $155 million. On February 21, 2023, the Utility and the SED filed a joint motion for approval of a settlement agreement (the “Zogg SED Settlement”). The Zogg SED Settlement provides that the Utility would (i) pay $10 million to California’s General Fund; (ii) implement certain enhancements to its vegetation management processes; (iii) incur $140 million in connection with certain initiatives specified in the Zogg SED Settlement, and the Utility may not seek recovery of this $140 million of costs. The SED agreed to refrain from instituting any further enforcement proceedings against the Utility related to the 2020 Zogg fire. The Zogg SED Settlement states that it does not constitute an admission or evidence of any wrongdoing, fault, omission, negligence, imprudence, or liability on the part of the Utility. In connection with the Zogg SED Settlement, PG&E Corporation and the Utility recorded a liability of $10 million reflected in Other current liabilities on the Consolidated Financial Statements for the year ended December 31, 2022. For the $140 million of costs for which the Utility will not seek recovery, the Utility expects to record disallowances as such costs are incurred. 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. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 29 complaints on behalf of at least 523 plaintiffs related to 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. The plaintiffs filed master complaints on August 6, 2021, and PG&E Corporation’s and the Utility’s answer was filed on September 7, 2021, and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. The court has set a trial date in the coordinated proceeding for August 14, 2023. In addition, on March 18, 2022, Cal Fire filed a complaint against the Utility in the coordinated proceeding seeking to recover approximately $34.5 million for fire suppression and other costs incurred in connection with the 2020 Zogg fire. The Utility filed an answer to Cal Fire’s complaint on May 3, 2022. The Utility and Cal Fire reached a settlement of Cal Fire’s claims and dismissal of Cal Fire’s complaint with prejudice was entered on December 22, 2022. On September 26, 2022, the Utility entered into a tolling agreement with Cal OES, which remains in effect. 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 Cal Fire’s determination of the cause and 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. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $375 million as of December 31, 2021 (before available insurance). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this report, PG&E Corporation and the Utility recorded additional charges for potential losses in connection with the 2020 Zogg fire of $25 million, for an aggregate liability of $400 million (before available insurance). PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other 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 following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 211 Accrued Losses 25 Payments (204) Balance at December 31, 2022 $ 32 The Utility has liability insurance for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. As of December 31, 2022, the Utility recorded an insurance receivable for $370 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $400 million probable loss estimate less an initial self-insured retention of $60 million, plus $30 million in legal fees incurred. Recovery under the Utility’s wildfire insurance policies for the 2021 Dixie fire will reduce the amount of insurance proceeds available for the 2020 Zogg fire by the same amount up to $600 million and vice versa. 2021 Dixie Fire According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire. On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund under AB 1054”). PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it. The District Attorneys’ Offices of Butte County, Plumas County, Shasta County, Lassen County and Tehama County (the “North State Counties”), as well as the SED and OEIS, have been investigating the fire; various other entities, which may include other state and federal law enforcement agencies, may also be investigating the fire. The United States Attorney’s Office for the Eastern District of California issued a subpoena for documents as well. PG&E Corporation and the Utility are cooperating with the investigations. Except for the investigation by the District Attorneys of the North State Counties, it is uncertain when any other such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2021 Dixie fire. This investigation is ongoing. On April 11, 2022, the Utility and the District Attorneys of the North State Counties filed a civil stipulated judgment to permanently resolve any potential state criminal prosecution of the Utility in connection with the 2021 Dixie fire (the “Dixie Stipulation”) without the Utility admitting any liability, and the court entered the judgment on that same date. Subject to the terms and conditions of the Dixie Stipulation, the Utility will pay a total of $34.75 million, which will not be recoverable through rates. Pursuant to the Dixie Stipulation, the Utility has also agreed to: (i) fill at least 80 new internal employee positions headquartered in or serving the North State Counties; (ii) take certain other wildfire mitigation actions consistent with its WMP; (iii) engage an independent compliance monitor for five years to monitor the Utility’s compliance with certain commitments under the Dixie Stipulation, including its commitments to carry out vegetation management and equipment inspections in the North State Counties consistent with its WMP; (iv) take good faith steps to initiate mediations with certain commercial timber landowners; and (v) initiate an expedited compensation program under which individuals whose homes, including mobile homes, were destroyed by the 2021 Dixie fire can submit an electronic claim form and supporting documentation, and the Utility will make them an offer to resolve their loss based on an objective, pre-determined valuation framework. The Dixie Stipulation also permanently resolved any potential state criminal prosecution of the Utility in connection with the 2021 Fly fire, which merged with the 2021 Dixie fire. In the first quarter of 2022, PG&E Corporation and the Utility recorded $34.75 million within Other current liabilities and Other noncurrent liabilities in connection with the Dixie Stipulation. As of December 31, 2022, $30.75 million has been paid pursuant to the Dixie Stipulation. On January 17, 2023, PG&E Corporation and the Utility reached an agreement with certain public entities to settle their claims for $24 million. As of February 16, 2023, PG&E Corporation and the Utility are aware of approximately 81 complaints on behalf of at least 2,094 plaintiffs related to the 2021 Dixie fire and expect that they may receive further such complaints. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 2, 2023, the court vacated the prior trial date and continued it to August 28, 2023. PG&E Corporation and the Utility expect to enter into an agreement with the insurance subrogation plaintiffs in the 2021 Dixie fire litigation to resolve their claims arising from the 2021 Dixie fire. 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 Cal Fire’s determination of the cause and 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 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.15 billion as of the year ended December 31, 2021 (before available recoveries). As a result of the public entities settlement, the aggregate liability increased to $1.175 billion as of December 31, 2022. PG&E Corporation’s and the Utility’s accrued estimated losses of $1.175 billion represent only claims based on the doctrine of inverse condemnation and do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other 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 including for state or federal fire suppression costs and damages related to federal land, (iv) evacuation costs, or (v) any other amounts that are not reasonably estimable. As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs from federal, state, county, or local agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national park and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 1,150 Accrued Losses 25 Payments (44) Bala |
SCHEDULE I _ CONDENSED FINANCIA
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT | 12 Months Ended |
Dec. 31, 2022 | |
Condensed Financial Information Disclosure [Abstract] | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT | PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Years Ended December 31, (in millions, except per share amounts) 2022 2021 2020 Administrative service revenue $ 109 $ 118 $ 127 Operating expenses (193) (124) (103) Interest income 3 — — Interest expense (261) (230) (149) Other income (expense) (201) (54) 13 Reorganization items, net — 1 (1,649) Equity in earnings of subsidiaries 2,154 137 411 Income (loss) before income taxes 1,611 (152) (1,350) Income tax benefit (132) (64) (46) Net Income (loss) $ 1,743 $ (88) $ (1,304) Other Comprehensive Income (Loss) Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates) $ 21 $ 7 $ (17) Total other comprehensive income (loss) 21 7 (17) Comprehensive Income (Loss) $ 1,764 $ (81) $ (1,321) Weighted Average Common Shares Outstanding, Basic (1) 2,235 2,463 1,257 Weighted Average Common Shares Outstanding, Diluted (1) 2,380 2,463 1,257 Net earnings (loss) per common share, basic $ 0.78 $ (0.05) $ (1.05) Net earnings (loss) per common share, diluted $ 0.73 $ (0.05) $ (1.05) (1) Includes 247,743,590 and 477,743,590 shares of common stock issued to ShareCo as of December 31, 2022 and 2021, respectively. PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2022 2021 ASSETS Current Assets Cash and cash equivalents $ 125 $ 126 Advances to affiliates 46 21 Income taxes receivable 10 10 Other current assets 12 12 Total current assets 193 169 Noncurrent Assets Equipment — 2 Accumulated depreciation — (2) Net equipment — — Investments in subsidiaries 33,021 30,232 Other investments 160 181 Deferred income taxes 423 297 Total noncurrent assets 33,604 30,710 Total Assets $ 33,797 $ 30,879 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Long-term debt, classified as current 27 27 Accounts payable – other 88 200 Other current liabilities 369 69 Total current liabilities 484 296 Noncurrent Liabilities Long-term debt 4,588 4,592 Other noncurrent liabilities 134 168 Total noncurrent liabilities 4,722 4,760 Common Shareholders’ Equity Common stock 36,132 35,129 Reinvested earnings (7,542) (9,286) Accumulated other comprehensive income (loss) 1 (20) Total common shareholders’ equity 28,591 25,823 Total Liabilities and Shareholders’ Equity $ 33,797 $ 30,879 PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2022 2021 2020 Cash Flows from Operating Activities: Net income (loss) $ 1,743 $ (88) $ (1,304) Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 95 51 28 Equity in earnings of subsidiaries (2,160) (139) (412) Deferred income taxes and tax credits, net (126) (60) (50) Reorganization items, net (Note 2) — (32) 1,548 Current income taxes receivable/payable — 2 — Liabilities subject to compromise — — 12 Other 339 81 97 Net cash used in operating activities (109) (185) (81) Cash Flows From Investing Activities: Investment in subsidiaries (994) — (12,986) Dividends received from subsidiaries (1) 1,275 — — Net cash provided by (used in) investing activities 281 — (12,986) Cash Flows From Financing Activities: Bridge facility financing fees — — (40) Proceeds from issuance of long-term debt — — 4,660 Repayment of long-term debt (28) (28) (664) Proceeds from (repayments of) intercompany note from the Utility (145) 145 — Common stock issued — — 7,582 Equity Units issued — — 1,304 Other — (29) — Net cash provided by (used in) financing activities (173) 88 12,842 Net change in cash and cash equivalents (1) (97) (225) Cash and cash equivalents at January 1 126 223 448 Cash and cash equivalents at December 31 $ 125 $ 126 $ 223 Supplemental disclosures of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (233) $ (207) $ (105) Income taxes, net — 1 — Supplemental disclosures of noncash investing and financing activities Common stock issued in satisfaction of liabilities — — 8,276 Changes to PG&E Corporation common stock and treasury stock in connection (2,337) 4,854 — (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock. |
SCHEDULE II _ CONSOLIDATED VALU
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022, 2021, and 2020 (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: 2022: Allowance for uncollectible accounts (1) $ 171 $ 146 $ — $ 151 $ 166 2021: Allowance for uncollectible accounts (1) $ 146 $ 136 $ — $ 111 $ 171 2020: Allowance for uncollectible accounts (1) $ 43 $ 138 $ — $ 35 $ 146 (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, 2022, 2021, and 2020 (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: 2022: Allowance for uncollectible accounts (1) $ 171 $ 146 $ — $ 151 $ 166 2021: Allowance for uncollectible accounts (1) $ 146 $ 136 $ — $ 111 $ 171 2020: Allowance for uncollectible accounts (1) $ 43 $ 138 $ — $ 35 $ 146 (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. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
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 through 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. |
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, 2022, the Utility also holds $213 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. |
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 GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. 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 Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility 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. |
Financial Assets Measured at Amortized Cost – Credit Losses | PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2022, PG&E Corporation and the Utility identified the following significant categories of financial assets. Trade Receivables Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses. As of December 31, 2022, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $88 million in the fourth quarter of 2022 as a result of the approximately $200 million CAPP funding from the State of California, which was received in November 2022. As of December 31, 2021, the Utility recorded a reduction to the allowance for doubtful accounts of approximately $207 million in the fourth quarter of 2021 as a result of the expected CAPP funding, which was received in January 2022. PG&E Corporation and the Utility recorded expected credit losses of $143 million and $154 million in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during 2022 and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC long-term regulatory asset balances were $3 million and $8 million, respectively. As of December 31, 2021, the RUBA current balancing accounts receivable balance was $127 million, and CPPMA and FERC long-term regulatory asset balances were $30 million and $12 million, respectively. Other Receivables and Available-For-Sale Debt Securities 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. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 15 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss. |
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. |
Inventories | Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, 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. |
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 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, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments. 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 3.74% in 2022, 3.82% in 2021, and 3.76% in 2020. 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 cost 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 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. |
Asset Retirement Obligations | PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 4 below. 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. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP, and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. 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 through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation was $4.1 billion and $3.9 billion at December 31, 2022 and 2021, respectively, based on the cost study performed as part of the 2021 NDCTP. The estimated probability-weighted, undiscounted decommissioning cash flows for the Utility’s nuclear power plants was $7.1 billion and $7.6 billion at December 31, 2022 and 2021, respectively. As of December 31, 2022, the Utility recorded an adjustment to the Diablo Canyon ARO to reflect the potential extension of the decommissioning commencement by five years until 2030 as a result of SB 846 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “Senate Bill 846” and “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals. The ARO liability decreased from $6.4 billion as of December 31, 2020 to $5.3 billion as of December 31, 2021, primarily due to a decrease in the nuclear decommissioning ARO of $1.3 billion. In December 2021, the Utility filed its 2021 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.0 billion. Relative to the 2018 NDCTP decision, the 2021 NDCTP application resulted in a decommissioning cost estimate that was decreased by $378 million on a non-escalated basis and $2.6 billion on an escalated basis. The escalated basis assumed that costs will be spread primarily over 56 years, which represents the assumption for how much time will be required for physical decommissioning of Units 1 and 2, and the Diablo Canyon independent spent fuel storage installation. This decrease reflected favorable changes in the scope and methods of planned decommissioning activities. Also as part of the 2021 NDCTP, the Utility filed modified escalation rates, in which the average total escalation factor decreased. Additionally, the credit-adjusted risk-free rate was greater in 2021 than in 2020. |
Nuclear Decommissioning Obligation and 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 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 to or recoverable from, respectively, 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. |
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. |
Government Assistance | PG&E Corporation and the Utility received various government assistance programs during the year ended December 31, 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance . Assembly Bill 180 On June 30, 2022, the Governor of California signed AB 180, which authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense as eligible costs are incurred. Senate Bill 846 On September 2, 2022, the Governor of California signed SB 846, which supports the extension of operations at Diablo Canyon through no later than 2030, with the potential for an earlier retirement date. Additionally, the State of California has authorized a loan of up to $1.4 billion pursuant to SB 846 to the Utility from the DWR to support the extension of plant operations. SB 846 further directs the Utility to take steps to secure funds from the DOE’s Civil Nuclear Credit Program, and any other potentially available federal funding, to repay the loan. The loan may be forgiven under certain circumstances. DWR Loan Agreement On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE's Civil Nuclear Credit Program” below). Under the loan agreement, the DWR will pay the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, but may not pay as shareholder profits or dividends or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and will no longer earn them on the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing pursuit of extension of the operating period and continued safe and reliable Diablo Canyon operations. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million. The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement, the Utility will recognize those forgiven loans as income related to government grants. The Utility plans to record the income related to government grants as a deduction to Operating and maintenance expense in the same period(s) that eligible costs are incurred. As of December 31, 2022, the consolidated financial statements reflected $312 million in Long-term debt, and a deduction of $38 million to Operating and maintenance expense for income related to government grants for performance-based disbursements. Operating and maintenance expense |
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 VIEs Receivables Securitization Program The SPV was created in connection with the Receivables Securitization Program and 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, 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 pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt, respectively, on the Consolidated Balance Sheets. The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. 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 2022 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2022 and 2021, the SPV had net accounts receivable of $3.6 billion and $3.3 billion, respectively, and outstanding borrowings of $1.2 billion and $974 million, respectively, under the Receivables Securitization Program. For more information, see Note 5 below. AB 1054 Securitization PG&E Recovery Funding LLC 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 financing order for the first AB 1054 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charge (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued recovery bonds secured by the Recovery Property. PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of senior secured recovery bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2022 and December 31, 2021, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion and $860 million, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below. SB 901 Securitization PG&E Wildfire Recovery Funding LLC 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 financing order for the SB 901 securitization transaction, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charge (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued recovery bonds secured by the SB 901 Recovery Property. PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during 2022 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.5 billion included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 6 below. 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 as of December 31, 2022, 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 or 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 as of December 31, 2022, it did not consolidate any of them. |
Voluntary Separation Program | In the second quarter of 2022, PG&E Corporation and the Utility enacted a VSP, which provides separation benefits to approximately 470 eligible employees who voluntarily agreed to terminate their employment under the program. The VSP includes certain one-time cash payments and a credit to the employee’s retirement health savings account. PG&E Corporation and the Utility account for the VSP as a special termination benefit with any costs of the special separation benefits recorded upon each employee’s irrevocable acceptance. During the year ended December 31, 2022, PG&E Corporation and the Utility recorded $80 million in Operating and maintenance expense on the Consolidated Statements of Income related to one-time cash payments in connection with the VSP. In addition, during the year ended December 31, 2022, VSP-related credits to employee retirement health savings accounts totaled $22 million. This amount will be paid using the PG&E Corporation and Utility postretirement medical plan trusts’ assets and does not impact income. |
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. |
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted | Debt In August 2020, the Financial Accounting Standards Board (“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 in an entity’s own equity. PG&E Corporation and the Utility adopted this ASU on January 1, 2022. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU. Reference Rate Reform On April 1, 2020, PG&E Corporation and the Utility adopted ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and elected the optional amendments for contract modifications prospectively. In December 2022, the FASB issued ASU No. 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 , which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. PG&E Corporation and the Utility adopted this ASU in December 2022 and will apply the guidance through December 31, 2024. There was no material impact on PG&E Corporation’s or the Utility’s Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU. |
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. |
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 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 through 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 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Summary of Revenues Disaggregated by Type of Customer | The following table presents the Utility’s revenues disaggregated by type of customer: Year Ended December 31, (in millions) 2022 2021 Electric Revenue from contracts with customers Residential $ 6,130 $ 6,089 Commercial 5,416 5,042 Industrial 1,626 1,493 Agricultural 1,830 1,565 Public street and highway lighting 77 73 Other, net (1) (247) (84) Total revenue from contracts with customers - electric 14,832 14,178 Regulatory balancing accounts (2) 228 953 Total electric operating revenue $ 15,060 $ 15,131 Natural gas Revenue from contracts with customers Residential $ 3,353 $ 2,759 Commercial 1,005 713 Transportation service only 1,534 1,346 Other, net (1) 163 140 Total revenue from contracts with customers - gas 6,055 4,958 Regulatory balancing accounts (2) 565 553 Total natural gas operating revenue 6,620 5,511 Total operating revenues $ 21,680 $ 20,642 (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. |
Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment | The Utility’s estimated service lives of its property, plant, and equipment were as follows: Estimated Service Balance at December 31, (in millions, except estimated service lives) Lives (years) 2022 2021 Electricity generating facilities (1) 5 to 75 $ 11,781 $ 11,217 Electricity distribution facilities 10 to 70 41,061 37,723 Electricity transmission facilities 15 to 75 16,413 15,516 Natural gas distribution facilities 20 to 60 15,366 14,100 Natural gas transmission and storage facilities 5 to 66 9,859 9,067 Financing lease 18 18 Construction work in progress 4,137 3,480 General plant and other 5 to 50 8,518 7,838 Total property, plant, and equipment 107,153 98,959 Accumulated depreciation (30,946) (29,131) Net property, plant, and equipment (2) $ 76,207 $ 69,828 (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 16 below. (2) Includes $1.8 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054. See Note 5 below. |
Changes In Asset Retirement Obligations | The following table summarizes the changes in ARO liability during 2022 and 2021, including nuclear decommissioning obligations: (in millions) 2022 2021 ARO liability at beginning of year $ 5,298 $ 6,412 Liabilities incurred 134 — Revision in estimated cash flows 325 (1,378) Accretion 213 287 Liabilities settled (58) (23) ARO liability at end of year $ 5,912 $ 5,298 |
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, 2022 consisted of the following: (in millions, net of income tax) Pension Other Customer Credit Trust Total Beginning balance $ (33) $ 18 $ — $ (15) Other comprehensive income before reclassifications: Loss on investments (net of taxes of $0, $0 and $3, respectively) — — (6) (6) Unrecognized net actuarial gain (net of taxes of $102, $99 and $0, respectively) 263 (255) — 8 Regulatory account transfer (net of taxes of $94, $99 and $0, respectively) (242) 255 — 13 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $1, $2 and $0, respectively) (1) (3) 5 — 2 Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively) (1) 1 (29) — (28) Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1) 2 24 — 26 Net current period other comprehensive income (loss) 21 — (6) 15 Ending balance $ (12) $ 18 $ (6) $ — (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 13 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, 2021 consisted of the following: (in millions, net of income tax) Pension Other Total Beginning balance $ (39) $ 17 $ (22) Other comprehensive income before reclassifications: Unrecognized net actuarial gain (net of taxes of $391 and $53, respectively) 1,007 137 1,144 Regulatory account transfer (net of taxes of $390 and $53, respectively) (1,003) (136) (1,139) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4) 10 6 Amortization of net actuarial (gain) loss (net of taxes of $2 and $9, respectively) (1) 4 (24) (20) Regulatory account transfer (net of taxes of $1 and $5, respectively) (1) 2 14 16 Net current period other comprehensive income 6 1 7 Ending balance $ (33) $ 18 $ (15) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. See Note 13 below for additional details. |
Schedule of Lease Expense | The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: Year Ended December 31, (in millions) 2022 2021 Operating lease fixed cost $ 500 $ 578 Operating lease variable cost 1,829 1,782 Total operating lease costs $ 2,329 $ 2,360 |
Schedule of Future Expected Operating Lease Payments | At December 31, 2022, the Utility’s future expected operating lease payments were as follows: (in millions) December 31, 2022 2023 $ 307 2024 150 2025 146 2026 143 2027 142 Thereafter 2,196 Total lease payments 3,084 Less imputed interest (1,610) Total $ 1,474 |
REGULATORY ASSETS, LIABILITIE_2
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Long-Term Regulatory Assets | Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery (in millions) 2022 2021 Pension benefits (1) $ 120 $ 708 Indefinitely Environmental compliance costs 1,193 1,089 32 years Utility retained generation (2) 86 133 4 years Price risk management 177 216 17 years Catastrophic event memorandum account (3) 1,085 1,119 1 - 3 years Wildfire expense memorandum account (4) 439 347 TBD years Fire hazard prevention memorandum account (5) 79 75 1 - 3 years Fire risk mitigation memorandum account (6) 65 44 1 - 3 years Wildfire mitigation plan memorandum account (7) 756 424 1 - 3 years Deferred income taxes (8) 2,730 1,849 51 years Insurance premium costs (9) 99 207 2 - 4 years Wildfire mitigation balancing account (10) 327 273 1 - 3 years Vegetation management balancing account (11) 2,276 1,411 1 - 3 years COVID-19 pandemic protection memorandum accounts (12) 26 49 TBD years Microgrid memorandum account (13) 213 163 1 - 3 years Financing costs (14) 211 175 Various SB 901 securitization (15) 5,378 — 30 years AROs in excess of recoveries (16) 120 — Various Other 1,063 925 Various Total long-term regulatory assets $ 16,443 $ 9,207 (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, 2022 and 2021, $44 million and $49 million in COVID-19 related costs were recorded to CEMA regulatory assets, respectively. Recovery of CEMA costs is subject to CPUC review and approval. (4) Represents incremental wildfire claims and outside legal expenses related to the 2021 Dixie fire and the 2022 Mosquito fire. 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 primarily associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. 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, the 2020 WMP for the period of January 1, 2020 through December 31, 2020, the 2021 WMP for the period of January 1, 2021 through December 31, 2021, and the 2022 WMP for the period of January 1, 2022 through December 31, 2022. 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 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, 2022 . Noncurrent balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) Represents vegetation management costs above 120% of adopted revenue requirements, which are subject to CPUC review and approval. (12) Includes costs associated with customer protections, including higher uncollectible costs related to the moratorium on electric and gas service disconnections program implementation costs, and higher accounts receivable financing costs for the period of March 4, 2020 to September 30, 2021. As of December 31, 2022, the Utility had recorded uncollectibles in the amount of $4 million for small business customers. The remaining $22 million is associated with program costs and higher accounts receivable financing costs. As of December 31, 2021, the Utility had recorded uncollectibles in the amount of $30 million for residential customers pending approval for recovery in the RUBA in addition to uncollectibles recorded for small business customers. The remaining $19 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval. (13) Includes costs associated with temporary generation, infrastructure upgrades, and community grid enablement programs associated with the implementation of microgrids. Amounts incurred are subject to CPUC review and approval. (14) Includes costs associated with long-term debt financing deemed recoverable under ASC 980 more than twelve months from the current date. These costs and their amortization period are reviewable and approved in the Utility’s cost of capital or other regulatory filings. Recovery periods vary because the balance consists of financing costs associated with debts that have different amortization periods depending on their maturity date. (15) In connection with the SB 901 securitization, the CPUC authorized the issuance of one or more series of recovery bonds in connection with the post-emergence transaction to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 6 below. (16) 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 asset also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. See Note 12 below. Recovery periods for this balance vary because the different sites and assets to which the ARO expenses are attributable have different recovery periods. |
Long-Term Regulatory Liabilities | Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2022 2021 Cost of removal obligations (1) $ 7,773 $ 7,306 Recoveries in excess of AROs (2) — 388 Public purpose programs (3) 1,062 946 Employee benefit plans (4) 904 1,229 Transmission tower wireless licenses (5) 430 446 SFGO sale (6) 264 343 SB 901 securitization (7) 5,800 — Other 1,397 1,341 Total long-term regulatory liabilities $ 17,630 $ 11,999 (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 held 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 12 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. (5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $430 million, $300 million will be refunded to FERC-jurisdictional customers, and $130 million will be refunded to CPUC-jurisdictional customers. (6) Represents the noncurrent portion of the net gain on the sale of the SFGO, which closed on September 17, 2021, that will be distributed to customers over a five-year period that began in 2022. |
Current Regulatory Balancing Accounts Receivable | Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable (in millions) 2022 2021 Electric distribution (1) $ 448 $ — Gas distribution and transmission (2) 72 — Energy procurement (3) 684 310 Public purpose programs (4) 358 321 Fire hazard prevention memorandum account (5) — 50 Fire risk mitigation memorandum account (6) — 14 Wildfire mitigation plan memorandum account (7) — 67 Wildfire mitigation balancing account (8) 2 91 General rate case memorandum accounts (9) 3 468 Vegetation management balancing account (10) 137 127 Insurance premium costs (11) 602 605 Wildfire expense memorandum account (12) — 440 Residential uncollectibles balancing accounts (13) 126 127 Catastrophic event memorandum account 144 — Other 688 379 Total regulatory balancing accounts receivable $ 3,264 $ 2,999 |
Current Regulatory Balancing Accounts Payable | Payable (in millions) 2022 2021 Electric distribution (1) $ — $ 121 Electric transmission (14) 228 24 Gas distribution and transmission (2) 66 83 Energy procurement (3) 428 211 Public purpose programs (4) 272 259 Nuclear decommissioning adjustment mechanism (15) 8 137 SFGO sale 152 21 Other 504 265 Total regulatory balancing accounts payable $ 1,658 $ 1,121 (1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings. (2) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case and other proceedings. (3) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities. (4) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency. (5) The FHPMA tracks costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (6) The FRMMA tracks costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019 and other incremental costs associated with fire risk mitigation. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (7) The WMPMA tracks costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019. Interim rate relief associated with the 2020 WMCE application ceased in May 2022, fully exhausting the current balance of the memorandum accounts. (8) The WMBA tracks costs associated with wildfire mitigation revenue requirement activities approved for cost recovery. (9) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2021 and the revenue requirements authorized in the final decision for the 2020 GRC. (10) The VMBA tracks routine and enhanced vegetation management activities approved for cost recovery. (11) 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, 2022, and 2021 there were $48 million and $82 million, respectively, in insurance premium costs recorded in Current regulatory assets. (12) The WEMA balancing accounts track insurance premium costs paid by the Utility between July 26, 2017 through December 31, 2019 that are incremental to those authorized in the 2017 GRC. On October 21, 2021, the CPUC adopted a final decision approving a settlement agreement among the Utility and other active parties that authorized the Utility to recover $445.5 million over a 12-month period beginning January 1, 2022. (13) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential customers. (14) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. (15) The nuclear decommissioning adjustment mechanism tracks costs primarily related to the closure of the Diablo Canyon power plant. |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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, 2022: (in millions) Termination Maximum Facility Limit Loans Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility June 2027 $ 4,400 (1) $ (1,930) $ (998) $ 1,472 Utility receivables securitization program (2) September 2024 1,389 (3) (1,184) — 205 (3) PG&E Corporation revolving credit facility June 2025 500 — — 500 Total credit facilities $ 6,289 $ (3,114) $ (998) $ 2,177 (1) On October 4, 2022, the Utility further amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders to $4.4 billion and (ii) extend the maturity date of such agreement to June 22, 2027 (subject to a one-year extension at the option of the Utility). Includes a $1.5 billion letter of credit sublimit. (2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 3 above. |
Schedule of Long-term Debt | The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: Balance at (in millions) Contractual Interest Rates December 31, 2022 December 31, 2021 PG&E Corporation Term Loan - Stated Maturity: 2025 variable rate (1) $ 2,681 $ 2,709 Senior Secured Notes due 2028 5.00% 1,000 1,000 Senior Secured Notes due 2030 5.25% 1,000 1,000 Less: current portion, net of unamortized discount and debt issuance costs (28) (26) Unamortized discount/premium and debt issuance costs, net (66) (90) Total PG&E Corporation Long-Term Debt 4,587 4,593 Utility First Mortgage Bonds - Stated Maturity: 2022 variable rate (2) — 500 2022 1.75% — 2,500 2023 1.70% - 4.25% 2,075 3,575 2024 3.25% - 3.75% 1,800 800 2025 3.45% - 4.95% 1,925 1,475 2026 2.95% - 3.15% 2,551 2,551 2027 2.10% - 5.45% 3,000 2,550 2028 3.00% - 4.65% 1,975 1,975 2029 4.20% 400 — 2030 4.55% 3,100 3,100 2031 2.50% - 3.25% 3,000 3,000 2032 4.40% - 5.90% 1,050 — 2040 3.30% - 4.50% 2,951 2,951 2041 4.20% - 4.50% 700 700 2042 3.75% - 4.45% 750 750 2043 4.60% 375 375 2044 4.75% 675 675 2045 4.30% 600 600 2046 4.00% - 4.25% 1,050 1,050 2047 3.95% 850 850 2050 3.50% - 4.95% 5,025 5,025 2052 5.25% 550 — Less: current portion, net of unamortized discount and debt issuance costs (2,072) (2,996) Unamortized discount, premium and debt issuance costs, net (195) (190) Total Utility First Mortgage Bonds 32,135 31,816 Recovery Bonds (3) 9,292 860 Less: current portion (168) (18) DWR Loan (4) 312 — Credit Facilities Receivables securitization program - Stated Maturity: 2024 variable rate (5) 1,184 974 2-Year Term Loan - Stated Maturity: 2024 variable rate (6) 400 — 18-month Term Loan - Stated Maturity: 2023 variable rate (7) — 1,441 Less: current portion — (1,441) Total Utility Long-Term Debt 43,155 33,632 Total PG&E Corporation Consolidated Long-Term Debt $ 47,742 $ 38,225 (1) At December 31, 2022 and 2021, the contractual London Interbank Offered Rate (“LIBOR”)-based interest rate on the term loan was 7.44% and 3.50%, respectively. (2) At December 31, 2021, the contractual LIBOR-based interest rate on $500 million of the first mortgage bonds was 1.69%. (3) The amount includes bonds related to AB 1054 and SB 901 securitization transactions, see “AB 1054” above and Note 6 for details on interest rates. (4) The Utility is not required to pay interest on the DWR loan, see Note 3 - Government Assistance. (5) At December 31, 2022, the contractual Secured Overnight Financing Rate (“SOFR”)-based interest rate on the receivables securitization program was 5.10% and at December 31, 2021. LIBOR-based interest rate on the receivables securitization program was 1.30%. (6) At December 31, 2022, the contractual SOFR-based interest rate on the term loan was 5.71%. |
Schedule Of Long Term Debt Repayments | PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2022 are reflected in the table below: (in millions, except interest rates) 2023 2024 2025 2026 2027 Thereafter Total PG&E Corporation Average fixed interest rate — % — % — % — % — % 5.13 % 5.13 % Fixed rate obligations $ — $ — $ — $ — $ — $ 2,000 $ 2,000 Variable interest rate as of December 31, 2022 7.13 % 7.13 % 7.13 % — % — % — % 7.13 % Variable rate obligations $ 28 $ 28 $ 2,625 $ — $ — $ — $ 2,681 Utility (1) Average fixed interest rate 2.91 % 3.40 % 3.82 % 3.10 % 3.22 % 4.12 % 3.84 % Fixed rate obligations $ 2,075 $ 1,800 $ 1,925 $ 2,551 $ 3,000 $ 23,051 $ 34,402 Variable interest rate as of December 31, 2022 — % 5.54 % — % — % — % — % 5.54 % Variable rate obligations $ — $ 1,584 $ — $ — $ — $ — $ 1,584 Recovery Bonds (2) AB 1054 obligations $ 38 $ 46 $ 48 $ 50 $ 51 $ 1,592 $ 1,825 SB 901 obligations $ 130 $ 129 $ 135 $ 141 $ 146 $ 6,786 $ 7,467 Total consolidated debt $ 2,271 $ 3,587 $ 4,733 $ 2,742 $ 3,197 $ 33,429 $ 49,959 (1) The balance excludes DWR loan, see Note 3 - Government Assistance. (2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see above and the 2021 Form 10-K. For SB 901 interest rates, see Note 6. |
SB 901 SECURITIZATION AND CUS_2
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | The Series 2022-A Recovery Bonds were issued in five tranches: Tranche Amount Interest Rate Final Maturity Date A-1 $ 540,000,000 3.594 % June 1, 2032 A-2 $ 540,000,000 4.263 % June 1, 2038 A-3 $ 360,000,000 4.377 % June 3, 2041 A-4 $ 1,260,000,000 4.451 % December 1, 2049 A-5 $ 900,000,000 4.674 % December 1, 2053 Tranche Amount Interest Rate Final Maturity Date B-1 $ 613,080,000 4.022 % June 1, 2033 B-2 $ 600,000,000 4.722 % June 1, 2039 B-3 $ 500,040,000 5.081 % June 3, 2043 B-4 $ 1,149,960,000 5.212 % December 1, 2049 B-5 $ 1,036,920,000 5.099 % June 1, 2054 |
Schedule of Financial Statement Impact of Securitization | The following tables illustrate the inception to date SB 901 securitization impact on the Utility’s regulatory assets and liabilities: SB 901 securitization regulatory asset (in millions) Regulatory asset balance at inception $ 5,500 Amortization (122) Balance at December 31, 2022 $ 5,378 SB 901 securitization regulatory liability (in millions) Regulatory liability balance at inception $ (5,540) Amortization 308 Additions (568) Balance at December 31, 2022 $ (5,800) |
COMMON STOCK AND SHARE-BASED _2
COMMON STOCK AND SHARE-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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 2022: (in millions) 2022 2021 2020 Stock Options $ — $ — $ 3 Restricted stock units 60 35 15 Performance shares 55 21 17 Total compensation expense (pre-tax) $ 115 $ 56 $ 35 Total compensation expense (after-tax) $ 83 $ 40 $ 25 |
Summary of Stock Option Activity | The following table summarizes stock option activity for PG&E Corporation and the Utility for 2022: Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 2,195,834 $ 7.42 $ — Granted (1) — — — Exercised — — — Forfeited or expired (43,702) 10.23 — Outstanding at December 31 2,152,132 7.36 2.41 — Vested or expected to vest at December 31 2,152,132 7.36 2.41 — Exercisable at December 31 2,152,132 $ 7.36 2.41 $ — (1) Represents additional payout of existing stock option grants. |
Schedule of Restricted Stock Units | The following table summarizes restricted stock unit activity for 2022: Number of Weighted Average Grant- Nonvested at January 1 10,090,375 $ 11.00 Granted 5,850,945 11.40 Vested (4,175,008) 10.96 Forfeited (788,192) 11.18 Nonvested at December 31 10,978,120 $ 11.21 |
Schedule of Performance Shares | The following table summarizes activity for performance shares in 2022: Number of Weighted Average Grant- Nonvested at January 1 8,567,009 $ 9.64 Granted 3,105,604 13.44 Vested — — Forfeited (650,559) 10.15 Nonvested at December 31 11,022,054 $ 10.68 |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method | 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 2022, 2021, and 2020. Year Ended December 31, (in millions, except per share amounts) 2022 2021 2020 Income (loss) available for common shareholders $ 1,800 $ (102) $ (1,318) Weighted average common shares outstanding, basic 1,987 1,985 1,257 Add incremental shares from assumed conversions: Employee share-based compensation 8 — — Equity Units 137 — — Weighted average common shares outstanding, diluted 2,132 1,985 1,257 Total earnings (loss) per common share, diluted $ 0.84 $ (0.05) $ (1.05) |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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: PG&E Corporation Utility Year Ended December 31, (in millions) 2022 2021 2020 2022 2021 2020 Current: Federal $ (1) $ — $ (26) $ (1) $ — $ (26) State — 1 (34) — — (34) Deferred: Federal (943) 543 258 (852) 588 290 State (389) 296 171 (348) 316 185 Tax credits (5) (4) (7) (5) (4) (7) Income tax provision (benefit) $ (1,338) $ 836 $ 362 $ (1,206) $ 900 $ 408 |
Schedule of Deferred Tax Assets and Liabilities | The following tables describe net deferred income tax assets and liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2022 2021 2022 2021 Deferred income tax assets: Tax carryforwards $ 7,156 $ 5,628 $ 6,868 $ 5,425 Compensation 157 185 80 108 Greenhouse gas allowance 239 157 239 157 Wildfire-related claims (1) 1,489 1,723 1,489 1,723 Operating lease liability 368 346 368 346 Transmission tower wireless licenses 254 266 254 266 Other (2) 197 121 177 136 Total deferred income tax assets $ 9,860 $ 8,426 $ 9,475 $ 8,161 Deferred income tax liabilities: Property related basis differences 9,374 8,847 9,363 8,835 Regulatory balancing accounts 1,376 1,193 1,376 1,193 Debt financing costs 465 501 465 501 Operating lease right of use asset 368 346 368 346 Income tax regulatory asset (3) 764 517 764 517 Other (4) 245 199 230 178 Total deferred income tax liabilities $ 12,592 $ 11,603 $ 12,566 $ 11,570 Total net deferred income tax liabilities $ 2,732 $ 3,177 $ 3,091 $ 3,409 (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 in PG&E Corporation’s and the Utility’s service area over the past several years. (2) Amounts include benefits, state taxes, 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. |
Schedule of Effective Income Tax Rate Reconciliation | The following table reconciles income tax expense at the federal statutory rate to the income tax provision: PG&E Corporation Utility Year Ended December 31, 2022 2021 2020 2022 2021 2020 Federal statutory income tax rate 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (75.8) 31.3 (15.3) (26.9) 24.1 19.1 Effect of regulatory treatment of fixed asset differences (2) (123.8) (71.5) 39.0 (49.2) (51.6) (44.9) Tax credits (3.2) (1.7) 1.5 (1.3) (1.2) (1.7) Fire Victim Trust (3) (160.9) 127.3 (44.9) (64.0) 91.9 51.7 Bankruptcy and emergence — — (37.6) — — 2.4 Other, net (4) 12.9 5.3 (2.1) 2.2 2.6 2.2 Effective tax rate (329.8) % 111.7 % (38.4) % (118.2) % 86.8 % 49.8 % (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 2022, 2021, and 2020, 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 tax benefit of the sale of shares by the Fire Victim Trust in 2022, a DTA write-off associated with the grantor trust election for the Fire Victim Trust in 2021 and an adjustment for the DTA write-off for difference between the liability recorded related to the Restructuring Support Agreement dated December 6, 2019 with the Official Committee of Tort Claimants and attorneys and other advisors and agents for certain holders of Fire Victim Claims (as defined therein), as amended and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust in 2020. PG&E Corporation includes the same adjustment as the Utility in these years as well as a permanent non-deductible equity backstop premium expense in 2020. (4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible penalty costs. |
Schedule of Change in Unrecognized Tax Benefits | The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2022 2021 2020 2022 2021 2020 Balance at beginning of year $ 498 $ 437 $ 420 $ 498 $ 437 $ 420 Reductions for tax position taken during a prior year (1) (23) (43) (1) (23) (43) Additions for tax position taken during the current year 73 85 60 73 85 60 Settlements — (1) — — (1) — Balance at end of year $ 570 $ 498 $ 437 $ 570 $ 498 $ 437 |
Schedule of Operating Loss and Tax Credit Carryforward Balances | The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, 2022 Expiration Federal: Net operating loss carryforward - Pre-2018 $ 3,447 2031 - 2036 Net operating loss carryforward - Post-2017 23,170 N/A Tax credit carryforward 152 2029 - 2041 State: Net operating loss carryforward $ 25,169 2039 - 2041 Tax credit carryforward 126 Various |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Volumes of Outstanding Derivative Contracts | The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments December 31, 2022 December 31, 2021 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 171,212,813 173,361,635 Options 27,785,000 14,420,000 Electricity (MWh) Forwards, Futures and Swaps 10,814,728 10,283,639 Options 215,600 288,000 Congestion Revenue Rights (3) 205,743,505 239,857,610 (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. |
Offsetting Liabilities | As of December 31, 2022, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 824 $ (170) $ 537 $ 1,191 Other noncurrent assets – other 306 — — 306 Current liabilities – other (238) 170 16 (52) Noncurrent liabilities – other (177) — — (177) Total commodity risk $ 715 $ — $ 553 $ 1,268 As of December 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 58 $ (9) $ 152 $ 201 Other noncurrent assets – other 169 — — 169 Current liabilities – other (53) 9 18 (26) Noncurrent liabilities – other (216) — — (216) Total commodity risk $ (42) $ — $ 170 $ 128 |
Offsetting Assets | As of December 31, 2022, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 824 $ (170) $ 537 $ 1,191 Other noncurrent assets – other 306 — — 306 Current liabilities – other (238) 170 16 (52) Noncurrent liabilities – other (177) — — (177) Total commodity risk $ 715 $ — $ 553 $ 1,268 As of December 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 58 $ (9) $ 152 $ 201 Other noncurrent assets – other 169 — — 169 Current liabilities – other (53) 9 18 (26) Noncurrent liabilities – other (216) — — (216) Total commodity risk $ (42) $ — $ 170 $ 128 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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. Fair Value Measurements At December 31, 2022 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 658 $ — $ — $ — $ 658 Fixed-income securities — 49 — — 49 Nuclear decommissioning trusts Short-term investments 117 — — — 117 Global equity securities 1,845 — — — 1,845 Fixed-income securities 1,094 791 — — 1,885 Assets measured at NAV — — — — 25 Total nuclear decommissioning trusts (2) 3,056 791 — — 3,872 Customer credit trust Short-term investments 19 — — — 19 Global equity securities 218 — — — 218 Fixed-income securities 216 292 — — 508 Total customer credit trust 453 292 — — 745 Price risk management instruments (Note 11) Electricity — 94 432 40 566 Gas — 604 — 327 931 Total price risk management instruments — 698 432 367 1,497 Rabbi trusts Short-term investments 25 — — — 25 Global equity securities 5 — — — 5 Fixed-income securities — 69 — — 69 Life insurance contracts — 64 — — 64 Total rabbi trusts 30 133 — — 163 Long-term disability trust Short-term investments 10 — — — 10 Assets measured at NAV — — — — 133 Total long-term disability trust 10 — — — 143 TOTAL ASSETS $ 4,207 $ 1,963 $ 432 $ 367 $ 7,127 Liabilities: Price risk management instruments (Note 11) Electricity $ — $ 10 $ 233 $ (20) $ 223 Gas — 172 — (166) 6 TOTAL LIABILITIES $ — $ 182 $ 233 $ (186) $ 229 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $575 million primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 289 $ — $ — $ — $ 289 Nuclear decommissioning trusts Short-term investments 22 — — — 22 Global equity securities 2,504 — — — 2,504 Fixed-income securities 1,158 866 — — 2,024 Assets measured at NAV — — — — 31 Total nuclear decommissioning trusts (2) 3,684 866 — — 4,581 Price risk management instruments (Note 10) Electricity — 9 214 6 229 Gas — 4 — 137 141 Total price risk management instruments — 13 214 143 370 Rabbi trusts Fixed-income securities — 104 — — 104 Life insurance contracts — 76 — — 76 Total rabbi trusts — 180 — — 180 Long-term disability trust Short-term investments 6 — — — 6 Assets measured at NAV — — — — 132 Total long-term disability trust 6 — — — 138 TOTAL ASSETS $ 3,979 $ 1,059 $ 214 $ 143 $ 5,558 Liabilities: Price risk management instruments (Note 10) Electricity $ — $ 11 $ 248 $ (24) $ 235 Gas — 10 — (3) 7 TOTAL LIABILITIES $ — $ 21 $ 248 $ (27) $ 242 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral. (2) Represents amount before deducting $783 million, primarily related to deferred taxes on appreciation of investment value. |
Fair Value Measurement Inputs and Valuation Techniques | Fair Value at (in millions) At December 31, 2022 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 305 $ 138 Market approach CRR auction prices $ (145.09) - 2,724.93 / 0.89 Power purchase agreements $ 127 $ 95 Discounted cash flow Forward prices $ (6.39) - 286.75 / 78.14 (1) Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) At December 31, 2021 Valuation Unobservable Fair Value Measurement Assets Liabilities Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 188 $ 93 Market approach CRR auction prices $ (40.77) - 2,265.94 / 0.40 Power purchase agreements $ 26 $ 155 Discounted cash flow Forward prices $ (7.97) - 256.20 / 47.17 (1) Represents price per MWh. |
Level 3 Reconciliation | The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2022 and 2021, respectively: Price Risk Management Instruments (in millions) 2022 2021 Liability balance as of January 1 $ (34) $ (72) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 233 38 Asset (Liability) balance as of December 31 $ 199 $ (34) (1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. |
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): At December 31, 2022 At December 31, 2021 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation $ 4,355 $ 4,490 $ 4,619 $ 4,796 Utility 32,847 27,666 31,816 35,803 |
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: (in millions) Amortized Total Total Total Fair As of December 31, 2022 Nuclear decommissioning trusts Short-term investments $ 117 $ — $ — $ 117 Global equity securities 413 1,468 (11) 1,870 Fixed-income securities 1,991 10 (116) 1,885 Total (1) $ 2,521 $ 1,478 $ (127) $ 3,872 As of December 31, 2021 Nuclear decommissioning trusts Short-term investments $ 22 $ — $ — $ 22 Global equity securities 479 2,066 (10) 2,535 Fixed-income securities 1,938 98 (12) 2,024 Total (1) $ 2,439 $ 2,164 $ (22) $ 4,581 (1) Represents amounts before deducting $575 million and $783 million as of December 31, 2022 and December 31, 2021, respectively, primarily related to deferred taxes on appreciation of investment value. |
Schedule of Available for Sale Securities Table | The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2022 Less than 1 year $ 42 1–5 years 624 5–10 years 400 More than 10 years 819 Total maturities of fixed-income securities $ 1,885 The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Total Total Fair As of December 31, 2022 Customer credit trust Short-term investments $ 19 $ — $ — $ 19 Global equity securities 219 13 (14) 218 Fixed-income securities 516 — (8) 508 Total $ 754 $ 13 $ (22) $ 745 |
Schedule of Activity for Debt and Equity Securities | The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2022 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 3,316 $ 1,678 $ 1,518 Gross realized gains on securities 2 286 159 Gross realized losses on securities (3) (19) (41) The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2022 Less than 1 year $ 79 1–5 years 123 5–10 years 120 More than 10 years 186 Total maturities of fixed-income securities $ 508 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2022 Proceeds from sales and maturities of customer credit trust investments $ 250 Gross realized gains on securities 10 Gross realized losses on securities (1) (41) (1) Includes $6 million of impaired debt securities which were written down to their respective fair values during the year ended December 31, 2022. |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
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 2022 and 2021: Pension Plan (in millions) 2022 2021 Change in plan assets: Fair value of plan assets at beginning of year $ 21,895 $ 20,759 Actual return on plan assets (4,916) 1,693 Company contributions 339 335 Benefits and expenses paid (949) (892) Fair value of plan assets at end of year $ 16,369 $ 21,895 Change in benefit obligation: Benefit obligation at beginning of year $ 22,759 $ 23,172 Service cost for benefits earned 575 587 Interest cost 692 645 Actuarial gain (1) (6,471) (752) Plan amendments — — Benefits and expenses paid (947) (893) Benefit obligation at end of year (2) $ 16,608 $ 22,759 Funded Status: Current liability $ (8) $ (9) Noncurrent liability (231) (856) Net liability at end of year $ (239) $ (865) (1) The actuarial gain for the year ended December 31, 2022 and December 31, 2021 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by unfavorable changes in the demographic assumptions. (2) PG&E Corporation’s accumulated benefit obligation was $15.4 billion and $20.4 billion at December 31, 2022 and 2021, respectively. Postretirement Benefits Other than Pensions (in millions) 2022 2021 Change in plan assets: Fair value of plan assets at beginning of year $ 3,102 $ 2,995 Actual return on plan assets (693) 193 Company contributions 26 10 Plan participant contribution 81 80 Benefits and expenses paid (180) (176) Fair value of plan assets at end of year $ 2,336 $ 3,102 Change in benefit obligation: Benefit obligation at beginning of year $ 1,766 $ 1,876 Service cost for benefits earned 62 63 Interest cost 53 51 Actuarial gain (1) (486) (152) Benefits and expenses paid (162) (156) Federal subsidy on benefits paid 3 4 Plan participant contributions 81 80 VSP related termination benefits (3) 22 — Benefit obligation at end of year $ 1,339 $ 1,766 Funded Status: (2) Noncurrent asset $ 997 $ 1,340 Noncurrent liability — (4) Net asset at end of year $ 997 $ 1,336 (1) The actuarial gain for the year ended December 31, 2022 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations, offset by unfavorable changes in demographic assumptions. The actuarial gain for the year ended December 31, 2021 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable claims cost changes (2) At December 31, 2022 and 2021, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $259 million and $266 million as of December 31, 2022, and $363 million and $359 million as of December 31, 2021, respectively. |
Components of Net Periodic Benefit Cost | Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows: Pension Plan (in millions) 2022 2021 2020 Service cost for benefits earned (1) $ 575 $ 587 $ 530 Interest cost 692 645 713 Expected return on plan assets (1,189) (1,046) (1,044) Amortization of prior service cost (4) (6) (6) Amortization of net actuarial loss 2 6 3 Net periodic benefit cost 76 186 196 Less: transfer to regulatory account (2) 254 147 136 Total expense recognized $ 330 $ 333 $ 332 (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 through future rates. Postretirement Benefits Other than Pensions (in millions) 2022 2021 2020 Service cost for benefits earned (1) $ 62 $ 63 $ 61 Interest cost 53 51 63 Expected return on plan assets (130) (137) (138) Amortization of prior service cost 7 14 14 Amortization of net actuarial loss (40) (33) (21) Special termination benefits 22 — — Net periodic benefit cost $ (26) $ (42) $ (21) (1) A portion of service costs are capitalized pursuant to ASU 2017-07. |
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. Pension Plan PBOP Plans December 31, December 31, 2022 2021 2020 2022 2021 2020 Discount rate 5.54 % 3.03 % 2.77 % 5.50 - 5.54% 2.97 - 3.04% 2.67 - 2.80% Rate of future compensation increases 3.80 % 3.80 % 3.80 % N/A N/A N/A Expected return on plan assets 6.10 % 5.50 % 5.10 % 3.70 - 7.30% 3.30 - 6.40% 3.10 - 6.10% Interest crediting rate for cash balance plan 4.19 % 1.95 % 1.95 % N/A N/A N/A |
Target Asset Allocation Percentages | The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2023 2022 2021 2023 2022 2021 Global equity securities 26 % 30 % 30 % 28 % 26 % 36 % Absolute return 1 % 2 % 2 % 1 % 1 % 1 % Real assets 8 % 8 % 8 % 3 % 3 % 5 % Fixed-income securities 65 % 60 % 60 % 68 % 70 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % |
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, 2022 and 2021. Fair Value Measurements At December 31, 2022 2021 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 461 $ 126 $ — $ 587 $ 552 $ 255 $ — $ 807 Global equity securities 1,430 — — 1,430 2,074 424 — 2,498 Absolute Return — — — — — 1 — 1 Real assets 426 — — 426 632 — — 632 Fixed-income securities 1,946 6,086 8 8,040 2,729 7,388 27 10,144 Assets measured at NAV — — — 5,886 — — — 7,972 Total $ 4,263 $ 6,212 $ 8 $ 16,369 $ 5,987 $ 8,068 $ 27 $ 22,054 PBOP Plans: Short-term investments $ 26 $ — $ — $ 26 $ 31 $ — $ — $ 31 Global equity securities 83 — — 83 105 — — 105 Real assets 29 — — 29 34 — — 34 Fixed-income securities 406 702 1 1,109 776 875 1 1,652 Assets measured at NAV — — — 1,100 — — — 1,296 Total $ 544 $ 702 $ 1 $ 2,347 $ 946 $ 875 $ 1 $ 3,118 Total plan assets at fair value $ 18,716 $ 25,172 |
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, 2022 and 2021: (in millions) For the year ended December 31, 2022 Fixed-Income Balance at beginning of year $ 27 Actual return on plan assets: Relating to assets still held at the reporting date 1 Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 6 Settlements (26) Balance at end of year $ 8 (in millions) For the year ended December 31, 2021 Fixed-Income Balance at beginning of year $ 12 Actual return on plan assets: Relating to assets still held at the reporting date 6 Relating to assets sold during the period (7) Purchases, issuances, sales, and settlements: Purchases 22 Settlements (6) Balance at end of year $ 27 |
Schedule of Estimated Benefits Expected to be Paid | As of December 31, 2022, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension PBOP Federal 2023 907 97 (4) 2024 996 98 (4) 2025 1028 100 (4) 2026 1057 94 (4) 2027 1,082 94 (4) Thereafter in the succeeding five years 5,702 475 (4) |
RELATED PARTY AGREEMENTS AND _2
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Schedule of Significant Related Party Transactions | The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2022 2021 2020 Utility revenues from: Administrative services provided to PG&E Corporation $ 3 $ 3 $ 3 Utility expenses from: Administrative services received from PG&E Corporation $ 104 $ 82 $ 108 Utility employee benefit due to PG&E Corporation 85 39 34 |
WILDFIRE-RELATED CONTINGENCIES
WILDFIRE-RELATED CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Wildfire-Related Claims | The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 769 Accrued Losses 225 Payments (344) Balance at December 31, 2022 $ 650 The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 211 Accrued Losses 25 Payments (204) Balance at December 31, 2022 $ 32 The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2021 Dixie fire since December 31, 2021. Loss Accrual (in millions) Balance at December 31, 2021 $ 1,150 Accrued Losses 25 Payments (44) Balance at December 31, 2022 $ 1,131 Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2022 are: Potential Recovery Source (in millions) 2022 Mosquito fire 2021 Dixie fire Insurance $ 45 $ 530 FERC TO rates 10 115 WEMA 50 388 Wildfire Fund — 175 Probable recoveries at December 31, 2022 $ 105 $ 1,208 The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets: Insurance Receivable (in millions) 2022 Mosquito fire 2021 Dixie fire 2020 Zogg fire 2019 Kincade fire Total Balance at December 31, 2021 $ — $ 563 $ 270 $ 414 $ 1,247 Accrued insurance recoveries (1) 45 (33) 33 — 45 Reimbursements — — (185) (313) (498) Balance at December 31, 2022 $ 45 $ 530 $ 118 $ 101 $ 794 |
OTHER CONTINGENCIES AND COMMI_2
OTHER CONTINGENCIES AND COMMITMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
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: Balance at (in millions) December 31, 2022 December 31, 2021 Topock natural gas compressor station $ 284 $ 299 Hinkley natural gas compressor station 110 123 Former MGP sites owned by the Utility or third parties (1) 750 667 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 112 104 Fossil fuel-fired generation facilities and sites (3) 26 70 Total environmental remediation liability $ 1,282 $ 1,263 (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. |
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, 2022: Power Purchase Agreements (in millions) Renewable Conventional Other Natural Nuclear Total 2023 $ 2,081 $ 482 $ 60 $ 1,746 $ 47 $ 4,416 2024 2,052 378 61 195 11 2,697 2025 2,040 715 61 140 — 2,956 2026 1,980 663 21 129 — 2,793 2027 1,919 579 7 53 — 2,558 Thereafter 17,807 1,565 13 — — 19,385 Total purchase commitments $ 27,879 $ 4,382 $ 223 $ 2,263 $ 58 $ 34,805 |
Schedule of Other Commitments | At December 31, 2022, the future minimum payments related to these commitments were as follows: (in millions) Other Commitments 2023 $ 88 2024 85 2025 83 2026 81 2027 80 Thereafter 3,518 Total minimum lease payments $ 3,935 |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Details) | 12 Months Ended |
Dec. 31, 2022 numberOfSegment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of operating segments (segment) | 1 |
BANKRUPTCY FILING (Chapter 11 C
BANKRUPTCY FILING (Chapter 11 Claims Process) (Details) notice in Thousands | Dec. 31, 2022 notice |
Debt Instrument [Line Items] | |
Proofs of claims | 100 |
Subrogation Wildfire Trust and Fire Victim Trust | |
Debt Instrument [Line Items] | |
Proofs of claims | 80 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (10K Narrative) (Details) ft² in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||
Nov. 17, 2022 USD ($) | Oct. 18, 2022 USD ($) | Nov. 30, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2022 USD ($) ft² employee | Dec. 31, 2021 USD ($) | Dec. 31, 2022 USD ($) ft² facility employee | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Jan. 31, 2023 ft² | Sep. 02, 2022 USD ($) | Jul. 20, 2022 USD ($) | May 10, 2022 USD ($) | Nov. 12, 2021 USD ($) | Oct. 23, 2020 USD ($) ft² | |
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Restricted cash | $ 16,000,000 | $ 213,000,000 | $ 16,000,000 | $ 213,000,000 | $ 16,000,000 | ||||||||||
Period for probable revenue recovery | 24 months | ||||||||||||||
Allowance for credit loss decrease | 88,000,000 | 207,000,000 | |||||||||||||
Credit losses | $ 143,000,000 | 154,000,000 | |||||||||||||
Decommissioning cost estimate | 4,000,000,000 | ||||||||||||||
Asset retirement obligation | 5,298,000,000 | 5,912,000,000 | 5,298,000,000 | 5,912,000,000 | 5,298,000,000 | $ 6,412,000,000 | |||||||||
Decrease in decommissioning cost | 1,300,000,000 | ||||||||||||||
Decrease in decommissioning cost, un-escalated | 378,000,000 | ||||||||||||||
Decrease in decommissioning cost, escalated | 2,600,000,000 | ||||||||||||||
Increase (decrease) in asset retirement obligation | $ 614,000,000 | ||||||||||||||
Government Assistance, Statement of Income or Comprehensive Income [Extensible Enumeration] | Operating and maintenance | ||||||||||||||
Litigation liability, current | 193,000,000 | $ 193,000,000 | |||||||||||||
Wildfire Fund asset | 461,000,000 | 460,000,000 | 461,000,000 | 460,000,000 | 461,000,000 | ||||||||||
Litigation contribution, net | 4,800,000,000 | 4,800,000,000 | |||||||||||||
Amortization and accretion | 477,000,000 | 517,000,000 | $ 413,000,000 | ||||||||||||
Insurance receivable | 1,247,000,000 | $ 794,000,000 | 1,247,000,000 | $ 794,000,000 | 1,247,000,000 | ||||||||||
Number of eligible employees | employee | 470 | 470 | |||||||||||||
Lease payments | $ 2,300,000,000 | 2,400,000,000 | |||||||||||||
Operating lease right of use asset | $ 1,234,000,000 | $ 1,311,000,000 | $ 1,234,000,000 | 1,311,000,000 | $ 1,234,000,000 | ||||||||||
Operating lease, right-of-use liability | $ 1,474,000,000 | $ 1,474,000,000 | |||||||||||||
Weighted average remaining lease term | 6 years 14 days | 19 years 7 months 6 days | 6 years 14 days | 19 years 7 months 6 days | 6 years 14 days | ||||||||||
Weighted average discount rate | 6.10% | 6.50% | 6.10% | 6.50% | 6.10% | ||||||||||
CAPP Funding | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Disbursement | $ 200,000,000 | ||||||||||||||
Performance-Based Disbursement | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Disbursement | $ 7 | ||||||||||||||
Maximum disbursement | 300,000,000 | ||||||||||||||
Performance-Based Disbursement | Utilities Operating Expense, Maintenance and Operations | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Reimbursement amount | $ 38,000,000 | ||||||||||||||
Civil Nuclear Credit Program | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Disbursement | $ 1,100,000,000 | ||||||||||||||
Long-Term Debt | Performance-Based Disbursement | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Reimbursement amount | 312,000,000 | ||||||||||||||
Other Current Liabilities | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Wildfire fund, noncurrent | $ 935,000,000 | 935,000,000 | |||||||||||||
One-time Termination Benefits | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Severance costs | 80,000,000 | ||||||||||||||
Credits to employee retirement health savings accounts | 22,000,000 | ||||||||||||||
2021 Dixie fire | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Insurance receivable | $ 563,000,000 | 530,000,000 | $ 563,000,000 | 530,000,000 | $ 563,000,000 | ||||||||||
2021 Dixie fire | Other noncurrent assets – other | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Insurance receivable | 175,000,000 | 175,000,000 | |||||||||||||
Regulatory Balancing Accounts Receivable | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Total regulatory balancing accounts | 2,999,000,000 | 3,264,000,000 | 2,999,000,000 | 3,264,000,000 | 2,999,000,000 | ||||||||||
COVID-19 Pandemic protection memorandum account | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Regulatory assets | 30,000,000 | 3,000,000 | 30,000,000 | 3,000,000 | 30,000,000 | ||||||||||
FERC TO rates | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Regulatory assets | 12,000,000 | 8,000,000 | 12,000,000 | 8,000,000 | 12,000,000 | ||||||||||
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Total regulatory balancing accounts | 127,000,000 | 126,000,000 | 127,000,000 | $ 126,000,000 | 127,000,000 | ||||||||||
Wildfire Fund Asset | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Finite-lived intangible asset, useful life | 15 years | ||||||||||||||
Recovery Bonds | Secured Debt | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Debt instrument, face amount | 860,000,000 | 1,800,000,000 | 860,000,000 | $ 1,800,000,000 | 860,000,000 | $ 860,000,000 | |||||||||
Long-term debt, gross | 860,000,000 | 9,292,000,000 | 860,000,000 | 9,292,000,000 | 860,000,000 | ||||||||||
Series 2022-A Recovery Bonds | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Debt instrument, face amount | $ 983,000,000 | ||||||||||||||
SB 901 Securitization | Secured Debt | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Debt instrument, face amount | 7,500,000,000 | 7,500,000,000 | $ 3,900,000,000 | $ 3,600,000,000 | |||||||||||
Pacific Gas & Electric Co (Utility) | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Restricted cash | 16,000,000 | 213,000,000 | 16,000,000 | $ 213,000,000 | $ 16,000,000 | ||||||||||
Composite depreciation rate | 3.74% | 3.82% | 3.76% | ||||||||||||
AFUDC debt recorded | $ 81,000,000 | $ 56,000,000 | $ 35,000,000 | ||||||||||||
AFUDC equity recorded | 184,000,000 | 133,000,000 | 140,000,000 | ||||||||||||
Nuclear decommissioning obligation accrued | 4,100,000,000 | 3,900,000,000 | |||||||||||||
Decommissioning cost estimate | 7,100,000,000 | 7,600,000,000 | |||||||||||||
Wildfire Fund asset | 461,000,000 | 460,000,000 | 461,000,000 | 460,000,000 | 461,000,000 | ||||||||||
Amortization and accretion | 477,000,000 | 517,000,000 | 477,000,000 | 517,000,000 | $ 413,000,000 | ||||||||||
Operating lease right of use asset | 1,232,000,000 | $ 1,311,000,000 | 1,232,000,000 | $ 1,311,000,000 | 1,232,000,000 | ||||||||||
Pacific Gas & Electric Co (Utility) | Oakland Headquarters Lease | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Rentable square feet | ft² | 488 | 488 | 910 | ||||||||||||
Lease, option payment letter of credit | $ 75,000,000 | ||||||||||||||
Lease, security letter of credit | 75,000,000 | ||||||||||||||
Purchase options, land, value | $ 892,000,000 | ||||||||||||||
Operating lease right of use asset | $ 535,000,000 | $ 535,000,000 | |||||||||||||
Leasehold improvements | 214,000,000 | 214,000,000 | |||||||||||||
Leasehold incentives | 137,000,000 | 137,000,000 | |||||||||||||
Operating lease, right-of-use liability | 672,000,000 | 672,000,000 | |||||||||||||
Pacific Gas & Electric Co (Utility) | Oakland Headquarters Lease | Subsequent Event | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Rentable square feet | ft² | 110 | ||||||||||||||
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Long-term debt, gross | 974,000,000 | 1,184,000,000 | 974,000,000 | $ 1,184,000,000 | 974,000,000 | ||||||||||
Pacific Gas & Electric Co (Utility) | Senate Bill 846 | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Debt instrument, face amount | $ 1,100,000,000 | ||||||||||||||
Pacific Gas & Electric Co (Utility) | Senate Bill 846 | Maximum | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Debt instrument, face amount | $ 1,400,000,000 | ||||||||||||||
Pacific Gas & Electric Co (Utility) | Diablo Canyon | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Number of generation facilities | facility | 2 | ||||||||||||||
Pacific Gas & Electric Co (Utility) | Humboldt Bay | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Number of generation facilities | facility | 1 | ||||||||||||||
PG&E AR Facility, LLC (SPV) | Receivables Securitization Program | |||||||||||||||
Public Utility, Property, Plant and Equipment [Line Items] | |||||||||||||||
Accounts receivable, net | $ 3,300,000,000 | $ 3,600,000,000 | $ 3,300,000,000 | $ 3,600,000,000 | $ 3,300,000,000 |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | $ 21,680 | $ 20,642 | $ 18,469 |
Electric | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 15,060 | 15,131 | 13,858 |
Natural gas | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 6,620 | 5,511 | 4,611 |
Pacific Gas & Electric Co (Utility) | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 21,680 | 20,642 | 18,469 |
Pacific Gas & Electric Co (Utility) | Electric | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 14,832 | 14,178 | |
Regulatory balancing accounts | 228 | 953 | |
Total operating revenues | 15,060 | 15,131 | 13,858 |
Pacific Gas & Electric Co (Utility) | Electric | Residential | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 6,130 | 6,089 | |
Pacific Gas & Electric Co (Utility) | Electric | Commercial | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 5,416 | 5,042 | |
Pacific Gas & Electric Co (Utility) | Electric | Industrial | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 1,626 | 1,493 | |
Pacific Gas & Electric Co (Utility) | Electric | Agricultural | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 1,830 | 1,565 | |
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 77 | 73 | |
Pacific Gas & Electric Co (Utility) | Electric | Other, net | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | (247) | (84) | |
Pacific Gas & Electric Co (Utility) | Natural gas | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 6,055 | 4,958 | |
Regulatory balancing accounts | 565 | 553 | |
Total operating revenues | 6,620 | 5,511 | $ 4,611 |
Pacific Gas & Electric Co (Utility) | Natural gas | Residential | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 3,353 | 2,759 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 1,005 | 713 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | 1,534 | 1,346 | |
Pacific Gas & Electric Co (Utility) | Natural gas | Other, net | |||
Disaggregation of Revenue [Abstract] | |||
Total operating revenues | $ 163 | $ 140 |
SUMMARY OF SIGNIFICANT ACCOUN_6
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, 2022 | Dec. 31, 2021 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 107,153 | $ 98,959 |
Accumulated depreciation | (30,946) | (29,131) |
Net property, plant, and equipment | 76,207 | 69,828 |
Electricity generating facilities | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | 11,781 | 11,217 |
Electricity generating facilities | Northern California Wildfire | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 1,800 | |
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 | $ 41,061 | 37,723 |
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 | $ 16,413 | 15,516 |
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 | $ 15,366 | 14,100 |
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 | $ 9,859 | 9,067 |
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 | |
Financing lease | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 18 | 18 |
Construction work in progress | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | 4,137 | 3,480 |
General plant and other | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total property, plant, and equipment | $ 8,518 | $ 7,838 |
General plant and other | Minimum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 5 years | |
General plant and other | Maximum | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Estimated Useful Lives (years) | 50 years |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
ARO liability at beginning of year | $ 5,298 | $ 6,412 |
Liabilities incurred | 134 | 0 |
Revision in estimated cash flows | 325 | (1,378) |
Accretion | 213 | 287 |
Liabilities settled | (58) | (23) |
ARO liability at end of year | $ 5,912 | $ 5,298 |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Beginning balance | $ 21,223 | $ 21,253 |
Net current period other comprehensive gain (loss) | 15 | 7 |
Ending balance | 23,075 | 21,223 |
Pension Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Net current period other comprehensive gain (loss) | 21 | 6 |
Other Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Net current period other comprehensive gain (loss) | 0 | 1 |
Customer Credit Trust | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Net current period other comprehensive gain (loss) | (6) | |
Accumulated Other Comprehensive Income (Loss) | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Beginning balance | (15) | (22) |
Ending balance | 0 | (15) |
Accumulated Other Comprehensive Income (Loss) | Pension Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Beginning balance | (33) | (39) |
Ending balance | (12) | (33) |
Accumulated Other Comprehensive Income (Loss) | Other Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Beginning balance | 18 | 17 |
Ending balance | 18 | 18 |
Accumulated Other Comprehensive Income (Loss) | Customer Credit Trust | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Beginning balance | 0 | |
Ending balance | (6) | 0 |
Amortization of net actuarial gain (loss) | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Loss on investments | (6) | |
Other comprehensive income before reclassifications: | 8 | 1,144 |
Amounts reclassified from other comprehensive income | 28 | 20 |
Amortization of net actuarial gain (loss) | Pension Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, before reclassification | 0 | |
Loss on investments | 0 | |
Other comprehensive income before reclassifications, tax | 102 | 391 |
Other comprehensive income before reclassifications: | 263 | 1,007 |
Amount attributable to tax, reclassification | 1 | 2 |
Amounts reclassified from other comprehensive income | (1) | (4) |
Amortization of net actuarial gain (loss) | Other Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, before reclassification | 0 | |
Loss on investments | 0 | |
Other comprehensive income before reclassifications, tax | 99 | 53 |
Other comprehensive income before reclassifications: | (255) | 137 |
Amount attributable to tax, reclassification | 11 | 9 |
Amounts reclassified from other comprehensive income | 29 | 24 |
Amortization of net actuarial gain (loss) | Customer Credit Trust | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, before reclassification | 3 | |
Loss on investments | (6) | |
Other comprehensive income before reclassifications, tax | 0 | |
Other comprehensive income before reclassifications: | 0 | |
Amount attributable to tax, reclassification | 0 | |
Amounts reclassified from other comprehensive income | 0 | |
Regulatory account transfer | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications: | 13 | (1,139) |
Amounts reclassified from other comprehensive income | (26) | (16) |
Regulatory account transfer | Pension Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications, tax | 94 | 390 |
Other comprehensive income before reclassifications: | (242) | (1,003) |
Amount attributable to tax, reclassification | 0 | 1 |
Amounts reclassified from other comprehensive income | (2) | (2) |
Regulatory account transfer | Other Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications, tax | 99 | 53 |
Other comprehensive income before reclassifications: | 255 | (136) |
Amount attributable to tax, reclassification | 9 | 5 |
Amounts reclassified from other comprehensive income | (24) | (14) |
Regulatory account transfer | Customer Credit Trust | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Other comprehensive income before reclassifications, tax | 0 | |
Other comprehensive income before reclassifications: | 0 | |
Amount attributable to tax, reclassification | 0 | |
Amounts reclassified from other comprehensive income | 0 | |
Amortization of prior service cost | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amounts reclassified from other comprehensive income | (2) | (6) |
Amortization of prior service cost | Pension Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, reclassification | 1 | 2 |
Amounts reclassified from other comprehensive income | 3 | 4 |
Amortization of prior service cost | Other Benefits | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, reclassification | 2 | 4 |
Amounts reclassified from other comprehensive income | (5) | $ (10) |
Amortization of prior service cost | Customer Credit Trust | ||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | ||
Amount attributable to tax, reclassification | 0 | |
Amounts reclassified from other comprehensive income | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Accounting Policies [Abstract] | ||
Operating lease fixed cost | $ 500 | $ 578 |
Operating lease variable cost | 1,829 | 1,782 |
Total operating lease costs | $ 2,329 | $ 2,360 |
SUMMARY OF SIGNIFICANT ACCOU_10
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Future Expected Operating Lease Payments | |
2023 | $ 307 |
2024 | 150 |
2025 | 146 |
2026 | 143 |
2027 | 142 |
Thereafter | 2,196 |
Total lease payments | 3,084 |
Less imputed interest | (1,610) |
Total | $ 1,474 |
REGULATORY ASSETS, LIABILITIE_3
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Narrative) (Details) - USD ($) $ in Millions | Oct. 21, 2021 | Dec. 31, 2022 | Dec. 31, 2021 |
Regulatory Assets [Line Items] | |||
Regulatory assets | $ 296 | $ 496 | |
Pacific Gas & Electric Co (Utility) | |||
Regulatory Assets [Line Items] | |||
Current regulatory liabilities | 1,120 | 698 | |
Deferral of current regulatory liabilities | 604 | ||
Regulatory assets | 296 | 496 | |
Insurance premium costs | |||
Regulatory Assets [Line Items] | |||
Regulatory assets | $ 48 | $ 82 | |
Settlement recovery amount | $ 445.5 |
REGULATORY ASSETS, LIABILITIE_4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Jun. 30, 2022 | Feb. 28, 2022 | Dec. 31, 2021 | |
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 16,443 | $ 9,207 | ||
Utility retained generation asset costs | 1,200 | |||
Customer Harm Threshold, post-emergence transaction, recovery bonds issued | $ 7,500 | |||
Initial shareholder contribution | 2,000 | |||
Pension benefits | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 120 | 708 | ||
Environmental compliance costs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 1,193 | 1,089 | ||
Recovery Period | 32 years | |||
Utility retained generation | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 86 | 133 | ||
Recovery Period | 4 years | |||
Price risk management | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 177 | 216 | ||
Recovery Period | 17 years | |||
Catastrophic event memorandum account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 1,085 | 1,119 | ||
Catastrophic event memorandum account | COVID-19 | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 44 | 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] | ||||
Regulatory assets | $ 439 | 347 | ||
Fire hazard prevention memorandum account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 79 | 75 | ||
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] | ||||
Regulatory assets | $ 65 | 44 | ||
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] | ||||
Regulatory assets | $ 756 | 424 | ||
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 taxes | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 2,730 | 1,849 | ||
Recovery Period | 51 years | |||
Insurance premium costs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 99 | 207 | ||
Insurance premium costs | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 2 years | |||
Insurance premium costs | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 4 years | |||
Wildfire mitigation balancing account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 327 | 273 | ||
Wildfire mitigation balancing account | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 1 year | |||
Cost percentage threshold requiring approval | 115% | |||
Wildfire mitigation balancing account | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 3 years | |||
Vegetation management balancing account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 2,276 | 1,411 | ||
Cost percentage threshold requiring approval | 120% | |||
Vegetation management balancing account | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 1 year | |||
Vegetation management balancing account | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 3 years | |||
COVID-19 Pandemic protection memorandum account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 26 | 49 | ||
COVID-19 pandemic protection memorandum account, undercollection bad debt | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 4 | 30 | ||
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | 22 | 19 | ||
Microgrid memorandum account | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 213 | 163 | ||
Microgrid memorandum account | Minimum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 1 year | |||
Microgrid memorandum account | Maximum | ||||
Regulatory Assets [Line Items] | ||||
Recovery Period | 3 years | |||
Financing costs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 211 | 175 | ||
SB 901 Securitization | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 5,378 | $ 5,500 | 0 | |
Recovery Period | 30 years | |||
Recoveries in excess of AROs | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 120 | 0 | ||
Other | ||||
Regulatory Assets [Line Items] | ||||
Regulatory assets | $ 1,063 | $ 925 |
REGULATORY ASSETS, LIABILITIE_5
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Jun. 30, 2022 | Dec. 31, 2021 | |
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | $ 17,630 | $ 11,999 | |
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers | 430 | ||
Authorized amount of shareholder tax benefits to be returned | 7,590 | ||
Federal Energy Regulatory Commission | |||
Regulatory Liabilities [Line Items] | |||
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers | 300 | ||
California Public Utilities Commission | |||
Regulatory Liabilities [Line Items] | |||
Proceeds received from sale of transmission tower wireless licenses, to be refunded to customers | 130 | ||
Cost of removal obligations | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 7,773 | 7,306 | |
Recoveries in excess of AROs | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 0 | 388 | |
Public purpose programs | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 1,062 | 946 | |
Employee benefit plans | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 904 | 1,229 | |
Transmission tower wireless licenses | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 430 | 446 | |
SFGO sale | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 264 | 343 | |
SB 901 Securitization | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | 5,800 | $ 5,540 | 0 |
Other | |||
Regulatory Liabilities [Line Items] | |||
Total long-term regulatory liabilities | $ 1,397 | $ 1,341 |
REGULATORY ASSETS, LIABILITIE_6
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | $ 1,658 | $ 1,121 |
Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 3,264 | 2,999 |
Electric distribution | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 0 | 121 |
Electric distribution | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 448 | 0 |
Electric transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 228 | 24 |
Gas distribution and transmission | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 66 | 83 |
Gas distribution and transmission | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 72 | 0 |
Energy procurement | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 428 | 211 |
Energy procurement | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 684 | 310 |
Public purpose programs | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 272 | 259 |
Public purpose programs | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 358 | 321 |
Fire hazard prevention memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 0 | 50 |
Fire risk mitigation memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 0 | 14 |
Wildfire mitigation plan memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 0 | 67 |
Wildfire mitigation balancing account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 2 | 91 |
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 3 | 468 |
Vegetation management balancing account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 137 | 127 |
Insurance premium costs | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 602 | 605 |
Wildfire expense memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 0 | 440 |
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 126 | 127 |
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 8 | 137 |
Catastrophic event memorandum account | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 144 | 0 |
SFGO sale | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 152 | 21 |
Other | Regulatory Balancing Accounts Payable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | 504 | 265 |
Other | Regulatory Balancing Accounts Receivable | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts | $ 688 | $ 379 |
DEBT (Outstanding Borrowings an
DEBT (Outstanding Borrowings and Availability) (Details) - USD ($) | Dec. 31, 2022 | Aug. 12, 2022 | Apr. 20, 2022 | Dec. 31, 2021 | Jun. 22, 2021 | Jul. 01, 2020 |
Revolving Credit Facility | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 6,289,000,000 | |||||
Loans Outstanding | (3,114,000,000) | |||||
Letters of Credit Outstanding | (998,000,000) | |||||
Facility Availability | 2,177,000,000 | |||||
Revolving Credit Facility | PG&E Corporation | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | 500,000,000 | $ 500,000,000 | ||||
Loans 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 | 4,400,000,000 | $ 4,000,000,000 | $ 3,500,000,000 | |||
Loans Outstanding | (1,930,000,000) | |||||
Letters of Credit Outstanding | (998,000,000) | |||||
Facility Availability | 1,472,000,000 | |||||
Letter of credit sublimit | 1,500,000,000 | |||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | 1,389,000,000 | $ 1,500,000,000 | $ 1,500,000,000 | |||
Loans Outstanding | (1,184,000,000) | $ (974,000,000) | ||||
Letters of Credit Outstanding | 0 | |||||
Facility Availability | 205,000,000 | |||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Minimum | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | 1,000,000,000 | |||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Maximum | ||||||
Debt [Line Items] | ||||||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 |
DEBT (Narrative) (Details)
DEBT (Narrative) (Details) | 12 Months Ended | |||||||||||||||||||
Oct. 04, 2022 | Apr. 20, 2022 USD ($) | Mar. 31, 2022 USD ($) | Feb. 18, 2022 USD ($) | Jul. 01, 2020 USD ($) numberOfClaimHolder numberOfExtensionOption | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Jan. 06, 2023 USD ($) | Nov. 30, 2022 USD ($) | Aug. 12, 2022 USD ($) | Aug. 05, 2022 USD ($) | Jun. 08, 2022 USD ($) | Apr. 04, 2022 USD ($) | Mar. 11, 2022 USD ($) | Aug. 11, 2021 USD ($) | Jun. 22, 2021 USD ($) | May 11, 2021 USD ($) | Apr. 23, 2021 USD ($) | Apr. 30, 2020 USD ($) | |
Debt [Line Items] | ||||||||||||||||||||
Repayments of long-term debt | $ 5,968,000,000 | $ 87,000,000 | $ 764,000,000 | |||||||||||||||||
Proceeds from the sale of long-term debt | $ 1,000,000,000 | |||||||||||||||||||
PG&E Corporation | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Repayments of long-term debt | 28,000,000 | 28,000,000 | 664,000,000 | |||||||||||||||||
Nothern California Wild Fire | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized | $ 7,500,000,000 | $ 7,500,000,000 | $ 7,500,000,000 | |||||||||||||||||
Nothern California Wild Fire | Fire Risk Mitigation Capital Expenditures | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized | 975,000,000 | $ 1,400,000,000 | $ 1,700,000,000 | |||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized, recorded | 212,000,000 | |||||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized, forecasted | 1,160,000,000 | |||||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized, pending | $ 350,000,000 | |||||||||||||||||||
Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Repayments of long-term debt | 5,941,000,000 | 59,000,000 | $ 100,000,000 | |||||||||||||||||
2020 Utility Term Loan Credit Agreement | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Repayments of long-term debt | $ 298,000,000 | |||||||||||||||||||
364-Day 2022A Tranche Loans | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 500,000,000 | |||||||||||||||||||
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 125,000,000 | |||||||||||||||||||
Credit spread adjustment | 0.10% | |||||||||||||||||||
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | SOFR | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Basis spread on variable rate | 1.25% | |||||||||||||||||||
364-Day 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | Base Rate | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Basis spread on variable rate | 0.25% | |||||||||||||||||||
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 400,000,000 | |||||||||||||||||||
Credit spread adjustment | 0.10% | |||||||||||||||||||
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | SOFR | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Basis spread on variable rate | 1.25% | |||||||||||||||||||
2-Year 2022B Tranche Loans | Pacific Gas & Electric Co (Utility) | Base Rate | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Basis spread on variable rate | 0.25% | |||||||||||||||||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 1,500,000,000 | 1,389,000,000 | $ 1,500,000,000 | |||||||||||||||||
Long-term debt, gross | 1,184,000,000 | 974,000,000 | ||||||||||||||||||
Increase in facility limit | $ 500,000,000 | |||||||||||||||||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Minimum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,000,000,000 | |||||||||||||||||||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | Maximum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,500,000,000 | |||||||||||||||||||
Revolving Credit Facility | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 6,289,000,000 | |||||||||||||||||||
Extension option, term | 1 year | |||||||||||||||||||
Long-term debt, gross | 3,114,000,000 | |||||||||||||||||||
Revolving Credit Facility | PG&E Corporation | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 500,000,000 | 500,000,000 | ||||||||||||||||||
Number of extensions | numberOfExtensionOption | 2 | |||||||||||||||||||
Extension option, term | 1 year | |||||||||||||||||||
Long-term debt, gross | 0 | |||||||||||||||||||
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | $ 3,500,000,000 | 4,400,000,000 | $ 4,000,000,000 | |||||||||||||||||
Number of extensions | numberOfClaimHolder | 2 | |||||||||||||||||||
Extension option, term | 1 year | 1 year | ||||||||||||||||||
Long-term debt, gross | 1,930,000,000 | |||||||||||||||||||
Intercompany Loan | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 145,000,000 | |||||||||||||||||||
Series 2022-A Recovery Bonds | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 983,000,000 | |||||||||||||||||||
Series 2022-A Recovery Bonds | Tranche One | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 215,000,000 | |||||||||||||||||||
Interest rate | 5.045% | |||||||||||||||||||
Series 2022-A Recovery Bonds | Tranche Two | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 200,000,000 | |||||||||||||||||||
Interest rate | 5.256% | |||||||||||||||||||
Series 2022-A Recovery Bonds | Tranche Three | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 568,000,000 | |||||||||||||||||||
Interest rate | 5.536% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 1,800,000,000 | 800,000,000 | ||||||||||||||||||
Debt instrument, face amount | $ 1,000,000,000 | |||||||||||||||||||
Interest rate | 3.25% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Interest rate | 3.25% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Maximum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Interest rate | 3.75% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2029 | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 400,000,000 | 0 | ||||||||||||||||||
Debt instrument, face amount | $ 400,000,000 | |||||||||||||||||||
Interest rate | 4.20% | 4.20% | ||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 1,050,000,000 | 0 | ||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | |||||||||||||||||||
Interest rate | 4.40% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Minimum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Interest rate | 4.40% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Maximum | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Interest rate | 5.90% | |||||||||||||||||||
First Mortgage Bonds, Stated Maturity 2052 | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Long-term debt, gross | $ 550,000,000 | $ 0 | ||||||||||||||||||
Debt instrument, face amount | $ 550,000,000 | |||||||||||||||||||
Interest rate | 5.25% | 5.25% | ||||||||||||||||||
4.950% Bonds | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | |||||||||||||||||||
Interest rate | 4.95% | |||||||||||||||||||
5.450% Bonds | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 450,000,000 | |||||||||||||||||||
Interest rate | 5.45% | |||||||||||||||||||
5.90% Bonds | Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 600,000,000 | |||||||||||||||||||
Interest rate | 5.90% | |||||||||||||||||||
First Mortgage Bonds Due 2033 | Pacific Gas & Electric Co (Utility) | Subsequent Event | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 750,000,000 | |||||||||||||||||||
Interest rate | 6.15% | |||||||||||||||||||
First Mortgage Bonds Due 2053 | Pacific Gas & Electric Co (Utility) | Subsequent Event | ||||||||||||||||||||
Debt [Line Items] | ||||||||||||||||||||
Debt instrument, face amount | $ 750,000,000 | |||||||||||||||||||
Interest rate | 675% |
DEBT (Schedule of Long-term Deb
DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Feb. 18, 2022 | Dec. 31, 2021 | Nov. 12, 2021 |
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | $ (2,268) | $ (4,481) | ||
Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | (2,241) | (4,455) | ||
PG&E Corporation | ||||
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | (27) | (27) | ||
New Debt | ||||
Debt [Line Items] | ||||
Long-term debt, net | 47,742 | 38,225 | ||
New Debt | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | 0 | (1,441) | ||
Long-term debt, net | 43,155 | 33,632 | ||
New Debt | PG&E Corporation | ||||
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | (28) | (26) | ||
Unamortized discount/premium and debt issuance costs, net | (66) | (90) | ||
Long-term debt, net | 4,587 | 4,593 | ||
Term Loan, Stated Maturity 2025 | PG&E Corporation | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 2,681 | $ 2,709 | ||
Term Loan, Stated Maturity 2025 | PG&E Corporation | LIBOR | ||||
Debt [Line Items] | ||||
Stated interest rate | 7.44% | 3.50% | ||
Senior Notes Due 2028 | PG&E Corporation | ||||
Debt [Line Items] | ||||
Stated interest rate | 5% | |||
Long-term debt, gross | $ 1,000 | $ 1,000 | ||
Senior Notes Due 2030 | PG&E Corporation | ||||
Debt [Line Items] | ||||
Stated interest rate | 5.25% | |||
Long-term debt, gross | $ 1,000 | 1,000 | ||
First Mortgage Bonds | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Less: current portion, net of unamortized discount and debt issuance costs | (2,072) | (2,996) | ||
Unamortized discount/premium and debt issuance costs, net | (195) | (190) | ||
Long-term debt, net | 32,135 | 31,816 | ||
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 0 | $ 500 | ||
First Mortgage Bonds, Variable, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | LIBOR | ||||
Debt [Line Items] | ||||
Stated interest rate | 1.69% | |||
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 1.75% | |||
Long-term debt, gross | $ 0 | $ 2,500 | ||
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 2,075 | 3,575 | ||
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 1.70% | |||
First Mortgage Bonds, Stated Maturity 2023 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.25% | |||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.25% | |||
Long-term debt, gross | $ 1,800 | 800 | ||
Recovery Bonds | $ 1,000 | |||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.25% | |||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.75% | |||
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 1,925 | 1,475 | ||
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.45% | |||
First Mortgage Bonds, Stated Maturity 2025 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.95% | |||
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 2,551 | 2,551 | ||
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 2.95% | |||
First Mortgage Bonds, Stated Maturity 2026 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.15% | |||
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 3,000 | 2,550 | ||
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 2.10% | |||
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 5.45% | |||
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 1,975 | 1,975 | ||
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3% | |||
First Mortgage Bonds, Stated Maturity 2028 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.65% | |||
First Mortgage Bonds, Stated Maturity 2029 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.20% | 4.20% | ||
Long-term debt, gross | $ 400 | 0 | ||
Recovery Bonds | $ 400 | |||
First Mortgage Bonds, Stated Maturity 2030 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.55% | |||
Long-term debt, gross | $ 3,100 | 3,100 | ||
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 3,000 | 3,000 | ||
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 2.50% | |||
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.25% | |||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.40% | |||
Long-term debt, gross | $ 1,050 | 0 | ||
Recovery Bonds | $ 450 | |||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.40% | |||
First Mortgage Bonds, Stated Maturity 2032 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 5.90% | |||
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 2,951 | 2,951 | ||
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.30% | |||
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.50% | |||
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 700 | 700 | ||
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.20% | |||
First Mortgage Bonds, Stated Maturity 2041 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.50% | |||
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 750 | 750 | ||
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.75% | |||
First Mortgage Bonds, Stated Maturity 2042 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.45% | |||
First Mortgage Bonds, Stated Maturity 2043 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.60% | |||
Long-term debt, gross | $ 375 | 375 | ||
First Mortgage Bonds, Stated Maturity 2044 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.75% | |||
Long-term debt, gross | $ 675 | 675 | ||
First Mortgage Bonds, Stated Maturity 2045 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.30% | |||
Long-term debt, gross | $ 600 | 600 | ||
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 1,050 | 1,050 | ||
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4% | |||
First Mortgage Bonds, Stated Maturity 2046 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.25% | |||
First Mortgage Bonds, Stated Maturity 2047 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.95% | |||
Long-term debt, gross | $ 850 | 850 | ||
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | $ 5,025 | 5,025 | ||
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | Minimum | ||||
Debt [Line Items] | ||||
Stated interest rate | 3.50% | |||
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility) | Maximum | ||||
Debt [Line Items] | ||||
Stated interest rate | 4.95% | |||
First Mortgage Bonds, Stated Maturity 2052 | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Stated interest rate | 5.25% | 5.25% | ||
Long-term debt, gross | $ 550 | 0 | ||
Recovery Bonds | $ 550 | |||
Recovery Bonds | Secured Debt | ||||
Debt [Line Items] | ||||
Long-term debt, gross | 9,292 | 860 | ||
Less: current portion, net of unamortized discount and debt issuance costs | (168) | (18) | ||
Recovery Bonds | 1,800 | 860 | $ 860 | |
DWR Loan | ||||
Debt [Line Items] | ||||
Long-term debt, net | 312 | 0 | ||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Long-term debt, gross | 1,184 | 974 | ||
Long-term debt, net | $ 1,184 | $ 974 | ||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | LIBOR | ||||
Debt [Line Items] | ||||
Debt, average interest rate | 1.30% | |||
Receivables Securitization Program | Pacific Gas & Electric Co (Utility) | SOFR | ||||
Debt [Line Items] | ||||
Debt, average interest rate | 5.10% | |||
2 Year Term Loan | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Term Loan | $ 400 | $ 0 | ||
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | ||||
Debt [Line Items] | ||||
Term Loan | $ 0 | $ 1,441 | ||
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | LIBOR | ||||
Debt [Line Items] | ||||
Stated interest rate | 2.38% | |||
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | SOFR | ||||
Debt [Line Items] | ||||
Stated interest rate | 5.71% |
DEBT (Schedule of Contractual R
DEBT (Schedule of Contractual Repayment Schedule) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Debt [Line Items] | |
Total consolidated debt | $ 49,959 |
Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 1,825 |
SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 7,467 |
Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.84% |
Fixed rate obligations | $ 34,402 |
Variable interest rate as of December 31, 2022 | 5.54% |
Variable rate obligations | $ 1,584 |
PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 5.13% |
Fixed rate obligations | $ 2,000 |
Variable interest rate as of December 31, 2022 | 7.13% |
Variable rate obligations | $ 2,681 |
2023 | |
Debt [Line Items] | |
Total consolidated debt | 2,271 |
2023 | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 38 |
2023 | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 130 |
2023 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 2.91% |
Fixed rate obligations | $ 2,075 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
2023 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2022 | 7.13% |
Variable rate obligations | $ 28 |
2024 | |
Debt [Line Items] | |
Total consolidated debt | 3,587 |
2024 | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 46 |
2024 | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 129 |
2024 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.40% |
Fixed rate obligations | $ 1,800 |
Variable interest rate as of December 31, 2022 | 5.54% |
Variable rate obligations | $ 1,584 |
2024 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2022 | 7.13% |
Variable rate obligations | $ 28 |
2025 | |
Debt [Line Items] | |
Total consolidated debt | 4,733 |
2025 | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 48 |
2025 | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 135 |
2025 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.82% |
Fixed rate obligations | $ 1,925 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
2025 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2022 | 7.13% |
Variable rate obligations | $ 2,625 |
2026 | |
Debt [Line Items] | |
Total consolidated debt | 2,742 |
2026 | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 50 |
2026 | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 141 |
2026 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.10% |
Fixed rate obligations | $ 2,551 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
2026 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
2027 | |
Debt [Line Items] | |
Total consolidated debt | 3,197 |
2027 | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 51 |
2027 | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 146 |
2027 | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 3.22% |
Fixed rate obligations | $ 3,000 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
2027 | PG&E Corporation | |
Debt [Line Items] | |
Average fixed interest rate | 0% |
Fixed rate obligations | $ 0 |
Variable interest rate as of December 31, 2022 | 0% |
Variable rate obligations | $ 0 |
Thereafter | |
Debt [Line Items] | |
Total consolidated debt | 33,429 |
Thereafter | Series 2022-A Recovery Bonds | |
Debt [Line Items] | |
Fixed rate obligations | 1,592 |
Thereafter | SB 901 Securitization | |
Debt [Line Items] | |
Fixed rate obligations | $ 6,786 |
Thereafter | Pacific Gas & Electric Co (Utility) | |
Debt [Line Items] | |
Average fixed interest rate | 4.12% |
Fixed rate obligations | $ 23,051 |
Variable interest rate as of December 31, 2022 | 0% |
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, 2022 | 0% |
Variable rate obligations | $ 0 |
SB 901 SECURITIZATION AND CUS_3
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||
Jul. 19, 2022 | May 09, 2022 | Jun. 30, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Jul. 25, 2022 | Jul. 20, 2022 | May 16, 2022 | May 10, 2022 | Apr. 04, 2022 | Feb. 28, 2022 | Feb. 18, 2022 | May 11, 2021 | Apr. 23, 2021 | Apr. 30, 2020 | |
Debt [Line Items] | |||||||||||||||||
Initial shareholder contribution | $ 2,000 | ||||||||||||||||
Regulatory assets | 16,443 | $ 9,207 | |||||||||||||||
Regulatory liabilities | 17,630 | 11,999 | |||||||||||||||
SB 901 securitization charges, net | 608 | 0 | $ 0 | ||||||||||||||
SB 901 Securitization | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Regulatory liabilities | $ 5,540 | 5,800 | 0 | ||||||||||||||
SB 901 Securitization | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Regulatory assets | 5,500 | 5,378 | 0 | ||||||||||||||
Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Regulatory assets | 16,443 | 9,207 | |||||||||||||||
Regulatory liabilities | 17,630 | 11,999 | |||||||||||||||
SB 901 securitization charges, net | 608 | 0 | $ 0 | ||||||||||||||
SB 901 Securitization | Secured Debt | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Initial shareholder contribution | 2,000 | ||||||||||||||||
Initial shareholder contribution, 2022 | 1,000 | ||||||||||||||||
Initial shareholder contribution, contributed in 2024 | 1,000 | ||||||||||||||||
Additional contributions funded by tax benefits | 7,590 | ||||||||||||||||
Contingent supplemental shareholder contribution | $ 775 | ||||||||||||||||
Percent of surplus of shareholder assets | 25% | ||||||||||||||||
Customer Harm Threshold, post-emergence transaction, stress test cost | $ 7,500 | ||||||||||||||||
Debt instrument, face amount | $ 7,500 | $ 3,900 | $ 3,600 | ||||||||||||||
Amount contributed | $ 520 | $ 480 | |||||||||||||||
SB 901 securitization charges, net | 608 | ||||||||||||||||
SB 901 Securitization | Secured Debt | Forecast | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
SB 901 securitization charges, net | $ 2,090 | ||||||||||||||||
Floating Rate Bonds | Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Debt instrument, face amount | $ 500 | ||||||||||||||||
1.75% Bonds | Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Debt instrument, face amount | $ 2,500 | ||||||||||||||||
Interest rate | 1.75% | ||||||||||||||||
First Mortgage Bonds Due 2023 | Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Debt instrument, face amount | $ 1,500 | ||||||||||||||||
Interest rate | 1.367% | ||||||||||||||||
364-Day 2022A Tranche Loans | Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Long-term debt, gross | $ 500 | ||||||||||||||||
First Mortgage Bonds, Stated Maturity 2024 | Pacific Gas & Electric Co (Utility) | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Debt instrument, face amount | $ 1,000 | ||||||||||||||||
Interest rate | 3.25% | ||||||||||||||||
Long-term debt, gross | $ 1,800 | $ 800 | |||||||||||||||
Nothern California Wild Fire | |||||||||||||||||
Debt [Line Items] | |||||||||||||||||
Customer Harm Threshold, post-emergence transaction, securitized | $ 7,500 | $ 7,500 | $ 7,500 | ||||||||||||||
Loss contingency, costs incurred | $ 7,500 |
SB 901 SECURITIZATION AND CUS_4
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Recovery Bonds) (Details) - USD ($) $ in Thousands | Nov. 30, 2022 | Jul. 20, 2022 | May 10, 2022 |
Series 2022-A Recovery Bonds | |||
Debt [Line Items] | |||
Amount | $ 983,000 | ||
Series 2022-A Recovery Bonds | Tranche One | |||
Debt [Line Items] | |||
Amount | $ 215,000 | ||
Interest rate | 5.045% | ||
Series 2022-A Recovery Bonds | Tranche Two | |||
Debt [Line Items] | |||
Amount | $ 200,000 | ||
Interest rate | 5.256% | ||
Series 2022-A Recovery Bonds | Tranche Three | |||
Debt [Line Items] | |||
Amount | $ 568,000 | ||
Interest rate | 5.536% | ||
Series 2022-A Recovery Bonds | Secured Debt | Tranche One | |||
Debt [Line Items] | |||
Amount | $ 540,000 | ||
Interest rate | 3.594% | ||
Series 2022-A Recovery Bonds | Secured Debt | Tranche Two | |||
Debt [Line Items] | |||
Amount | $ 540,000 | ||
Interest rate | 4.263% | ||
Series 2022-A Recovery Bonds | Secured Debt | Tranche Three | |||
Debt [Line Items] | |||
Amount | $ 360,000 | ||
Interest rate | 4.377% | ||
Series 2022-A Recovery Bonds | Secured Debt | Tranche Four | |||
Debt [Line Items] | |||
Amount | $ 1,260,000 | ||
Interest rate | 4.451% | ||
Series 2022-A Recovery Bonds | Secured Debt | Tranche Five | |||
Debt [Line Items] | |||
Amount | $ 900,000 | ||
Interest rate | 4.674% | ||
Series 2022-B Recovery Bonds | Secured Debt | Tranche One | |||
Debt [Line Items] | |||
Amount | $ 613,080 | ||
Interest rate | 4.022% | ||
Series 2022-B Recovery Bonds | Secured Debt | Tranche Two | |||
Debt [Line Items] | |||
Amount | $ 600,000 | ||
Interest rate | 4.722% | ||
Series 2022-B Recovery Bonds | Secured Debt | Tranche Three | |||
Debt [Line Items] | |||
Amount | $ 500,040 | ||
Interest rate | 5.081% | ||
Series 2022-B Recovery Bonds | Secured Debt | Tranche Four | |||
Debt [Line Items] | |||
Amount | $ 1,149,960 | ||
Interest rate | 5.212% | ||
Series 2022-B Recovery Bonds | Secured Debt | Tranche Five | |||
Debt [Line Items] | |||
Amount | $ 1,036,920 | ||
Interest rate | 5.099% |
SB 901 SECURITIZATION AND CUS_5
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Financial Statement Impact) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Debt [Line Items] | ||
Regulatory assets | $ 16,443 | $ 9,207 |
Ending balance | 16,443 | |
Regulatory liability balance at inception | (11,999) | |
Ending balance | (17,630) | |
SB 901 Securitization Inception | ||
Debt [Line Items] | ||
Regulatory liability balance at inception | (5,540) | |
Amortization | 308 | |
Additions | (568) | |
Ending balance | (5,800) | |
SB 901 Securitization Inception | ||
Debt [Line Items] | ||
Regulatory assets | 5,378 | $ 5,500 |
Amortization | (122) | |
Ending balance | $ 5,378 |
COMMON STOCK AND SHARE-BASED _3
COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($) | 12 Months Ended | ||||||||||
Feb. 16, 2023 | Jan. 09, 2023 | Dec. 20, 2022 | Sep. 16, 2022 | Jun. 17, 2022 | May 28, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Jul. 08, 2021 | Apr. 30, 2021 | |
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Common stock, shares outstanding (in shares) | 1,987,784,948 | 1,985,400,540 | |||||||||
Treasury stock, shares at cost (in shares) | 247,743,590 | 477,743,590 | |||||||||
Shares outstanding (in shares) | 2,466,208,388 | ||||||||||
Equity capital structure percentage | 5,200% | ||||||||||
Equity capital structure, waiver period | 5 years | ||||||||||
Non-GAAP core earnings threshold | $ 6,200,000,000 | ||||||||||
Shares available for LTIP award (in shares) | 53,350,101 | ||||||||||
Weighted average grant date fair value of granted shares (in dollars per share) | $ 11.40 | $ 11.01 | $ 9.25 | ||||||||
Total fair value | $ 46,000,000 | $ 19,000,000 | $ 31,000,000 | ||||||||
Total unrecognized compensation costs | $ 74,000,000 | ||||||||||
Remaining weighted average period | 1 year 5 months 23 days | ||||||||||
Pacific Gas & Electric Co (Utility) | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Common stock, shares outstanding (in shares) | 230,000,000 | ||||||||||
Pacific Gas & Electric Co (Utility) | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Common stock, shares outstanding (in shares) | 264,374,809 | 264,374,809 | |||||||||
Shares outstanding (in shares) | 264,374,809 | ||||||||||
Common stock dividends paid | $ 425,000,000 | $ 425,000,000 | $ 425,000,000 | $ 1,275,000,000 | $ 0 | $ 0 | |||||
Fire Victim Trust | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Number of shares exchanged (in shares) | 230,000,000 | ||||||||||
Shares sold, tax impact | $ 870,000,000 | ||||||||||
Fire Victim Trust | Subsequent Event | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Number of shares exchanged (in shares) | 60,000,000 | ||||||||||
Number of shares sold (in shares) | 290,000,000 | ||||||||||
2014 LTIP, Amended | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Number of shares issued for LTIP, maximum (in shares) | 91,000,000 | ||||||||||
Stock Options | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Granted (in shares) | 0 | 0 | |||||||||
Weighted-average period | 11 months 8 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 | $ 0 | ||||||||||
Granted (in shares) | 0 | ||||||||||
Restricted stock units | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Award vesting period | 3 years | ||||||||||
Tax detriment | $ 4,000,000 | ||||||||||
Performance shares | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Award vesting period | 3 years | ||||||||||
Industry performance period | 3 years | ||||||||||
Award grant date fair value recognition period | 3 years | ||||||||||
Performance shares granted (in dollars per share) | $ 13.44 | $ 11.83 | $ 9.62 | ||||||||
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $ 43,000,000 | ||||||||||
PG&E Corporation | Subsequent Event | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Common stock, shares outstanding, adjusted (in shares) | 1,800,721,208 | ||||||||||
PG&E Corporation | Equity Units | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Stock issued during period, shares, new issues (in shares) | 16,000,000 | ||||||||||
PG&E Corporation | Minimum | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Percentage of equity security ownership with board of director approval | 4.75% | 4.75% | |||||||||
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% | ||||||||||
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared | 100% | ||||||||||
PG&E Corporation | Minimum | Subsequent Event | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Percentage of equity security ownership with board of director approval | 3.46% | ||||||||||
PG&E Corporation | Minimum | Common Stock | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Amount of shares, right to receive | 138,000,000 | ||||||||||
PG&E Corporation | Maximum | Revolving Credit Facility | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Debt, ratio of total consolidated debt to consolidated capitalization | 70% | ||||||||||
PG&E Corporation | Maximum | Common Stock | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Amount of shares, right to receive | 168,000,000 | ||||||||||
PG&E Corporation | At The Market Equity Distribution Program | Common Stock | |||||||||||
Schedule of Capitalization, Equity [Line Items] | |||||||||||
Sale of stock, number of shares issued in transaction, amount | $ 400,000,000 |
COMMON STOCK AND SHARE-BASED _4
COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 115 | $ 56 | $ 35 |
Total compensation expense (after-tax) | 83 | 40 | 25 |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 0 | 0 | 3 |
Restricted stock units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | 60 | 35 | 15 |
Performance shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense (pre-tax) | $ 55 | $ 21 | $ 17 |
COMMON STOCK AND SHARE-BASED _5
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Stock Options - $ / shares | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Number of Stock Options | ||
Granted (in shares) | 0 | 0 |
2014 LTIP | ||
Number of Stock Options | ||
Outstanding, beginning of period (in shares) | 2,195,834 | |
Granted (in shares) | 0 | |
Exercised (in shares) | 0 | |
Forfeited or expired (in shares) | (43,702) | |
Outstanding, end of period (in shares) | 2,152,132 | 2,195,834 |
Vested or expected to vest (in shares) | 2,152,132 | |
Exercisable (in shares) | 2,152,132 | |
Weighted Average Grant- Date Fair Value | ||
Outstanding, beginning of period (in dollars per share) | $ 7.42 | |
Forfeited or expired (in dollars per share) | 10.23 | |
Outstanding, end of period (in dollars per share) | 7.36 | $ 7.42 |
Vested or expected to vest (in dollars per share) | 7.36 | |
Exercisable (in dollars per share) | $ 7.36 | |
Weighted Average Remaining Contractual Term | ||
Outstanding | 2 years 4 months 28 days | |
Expected to vest | 2 years 4 months 28 days | |
Exercisable | 2 years 4 months 28 days |
COMMON STOCK AND SHARE-BASED _6
COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Number of Restricted Stock Units | |||
Nonvested, beginning balance (in shares) | 10,090,375 | ||
Granted (in shares) | 5,850,945 | ||
Vested (in shares) | (4,175,008) | ||
Forfeited (in shares) | (788,192) | ||
Nonvested, ending balance (in shares) | 10,978,120 | 10,090,375 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested, beginning balance (in dollars per share) | $ 11 | ||
Granted (in dollars per share) | 11.40 | $ 11.01 | $ 9.25 |
Vested (in dollars per share) | 10.96 | ||
Forfeited (in dollars per share) | 11.18 | ||
Nonvested, ending balance (in dollars per share) | $ 11.21 | $ 11 |
COMMON STOCK AND SHARE-BASED _7
COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Number of Restricted Stock Units | |||
Nonvested , beginning balance (in shares) | 8,567,009 | ||
Granted (in shares) | 3,105,604 | ||
Vested (in shares) | 0 | ||
Forfeited (in shares) | (650,559) | ||
Nonvested, ending balance (in shares) | 11,022,054 | 8,567,009 | |
Weighted Average Grant- Date Fair Value | |||
Nonvested, beginning balance (in dollars per share) | $ 9.64 | ||
Granted (in dollars per share) | 13.44 | $ 11.83 | $ 9.62 |
Vested (in dollars per share) | 0 | ||
Forfeited (in dollars per share) | 10.15 | ||
Nonvested, ending balance (in dollars per share) | $ 10.68 | $ 9.64 |
PREFERRED STOCK (Details)
PREFERRED STOCK (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||||
Dec. 15, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Jan. 31, 2022 | |
Preferred Stock [Line Items] | |||||
Cumulative and unpaid dividends | $ 59.1 | ||||
Preferred stock dividend requirement | $ 3.5 | $ 13 | |||
Pacific Gas & Electric Co (Utility) | |||||
Preferred Stock [Line Items] | |||||
Preferred stock dividend requirement | 11 | ||||
Preferred stock dividend requirement | $ 14 | $ 14 | $ 14 | ||
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 | $ 145 | |||
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% | 5% | |||
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum | |||||
Preferred Stock [Line Items] | |||||
Preferred stock interest rate | 6% | 6% | |||
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | |||||
Preferred Stock [Line Items] | |||||
Redeemable preferred stock outstanding | $ 113 | $ 113 | |||
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% | 5% | |||
PG&E Corporation | |||||
Preferred Stock [Line Items] | |||||
Preferred stock, shares authorized (in shares) | 400,000,000 | ||||
Preferred stock, shares outstanding (in shares) | 0 | ||||
$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 | ||||
$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 |
EARNINGS PER SHARE (Reconciliat
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Earnings Per Share [Abstract] | |||
Income (loss) available for common shareholders | $ 1,800 | $ (102) | $ (1,318) |
Weighted average common shares outstanding, basic (in shares) | 1,987 | 1,985 | 1,257 |
Add incremental shares from assumed conversions: | |||
Employee share-based compensation (in shares) | 8 | 0 | 0 |
Equity Units (in shares) | 137 | 0 | 0 |
Weighted average common share outstanding, diluted (in shares) | 2,132 | 1,985 | 1,257 |
Total earnings (loss) per common share, diluted (in dollars per share) | $ 0.84 | $ (0.05) | $ (1.05) |
INCOME TAXES (Schedule of Incom
INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Current: | |||
Federal | $ (1) | $ 0 | $ (26) |
State | 0 | 1 | (34) |
Deferred: | |||
Federal | (943) | 543 | 258 |
State | (389) | 296 | 171 |
Tax credits | (5) | (4) | (7) |
Income tax provision (benefit) | (1,338) | 836 | 362 |
Pacific Gas & Electric Co (Utility) | |||
Current: | |||
Federal | (1) | 0 | (26) |
State | 0 | 0 | (34) |
Deferred: | |||
Federal | (852) | 588 | 290 |
State | (348) | 316 | 185 |
Tax credits | (5) | (4) | (7) |
Income tax provision (benefit) | $ (1,206) | $ 900 | $ 408 |
INCOME TAXES (Schedule of Defer
INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Pacific Gas & Electric Co (Utility) | ||
Deferred income tax assets: | ||
Tax carryforwards | $ 6,868 | $ 5,425 |
Compensation | 80 | 108 |
Greenhouse gas allowance | 239 | 157 |
Wildfire-related claims | 1,489 | 1,723 |
Operating lease liability | 368 | 346 |
Transmission tower wireless licenses | 254 | 266 |
Other | 177 | 136 |
Total deferred income tax assets | 9,475 | 8,161 |
Deferred income tax liabilities: | ||
Property related basis differences | 9,363 | 8,835 |
Regulatory balancing accounts | 1,376 | 1,193 |
Debt financing costs | 465 | 501 |
Operating lease right of use asset | 368 | 346 |
Income tax regulatory asset | 764 | 517 |
Other | 230 | 178 |
Total deferred income tax liabilities | 12,566 | 11,570 |
Total net deferred income tax liabilities | 3,091 | 3,409 |
PG&E Corporation | ||
Deferred income tax assets: | ||
Tax carryforwards | 7,156 | 5,628 |
Compensation | 157 | 185 |
Greenhouse gas allowance | 239 | 157 |
Wildfire-related claims | 1,489 | 1,723 |
Operating lease liability | 368 | 346 |
Transmission tower wireless licenses | 254 | 266 |
Other | 197 | 121 |
Total deferred income tax assets | 9,860 | 8,426 |
Deferred income tax liabilities: | ||
Property related basis differences | 9,374 | 8,847 |
Regulatory balancing accounts | 1,376 | 1,193 |
Debt financing costs | 465 | 501 |
Operating lease right of use asset | 368 | 346 |
Income tax regulatory asset | 764 | 517 |
Other | 245 | 199 |
Total deferred income tax liabilities | 12,592 | 11,603 |
Total net deferred income tax liabilities | $ 2,732 | $ 3,177 |
INCOME TAXES (Schedule of Effec
INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pacific Gas & Electric Co (Utility) | |||
Operating Loss Carryforwards [Line Items] | |||
Federal statutory income tax rate | 21% | 21% | 21% |
State income tax (net of federal benefit) | (26.90%) | 24.10% | 19.10% |
Effect of regulatory treatment of fixed asset differences | (49.20%) | (51.60%) | (44.90%) |
Tax credits | (1.30%) | (1.20%) | (1.70%) |
Fire Victim Trust | (0.640) | 0.919 | 0.517 |
Bankruptcy and emergence | 0% | 0% | 2.40% |
Other, net | 2.20% | 2.60% | 2.20% |
Effective tax rate | (118.20%) | 86.80% | 49.80% |
PG&E Corporation | |||
Operating Loss Carryforwards [Line Items] | |||
Federal statutory income tax rate | 21% | 21% | 21% |
State income tax (net of federal benefit) | (75.80%) | 31.30% | (15.30%) |
Effect of regulatory treatment of fixed asset differences | (123.80%) | (71.50%) | 39% |
Tax credits | 3.20% | 1.70% | (1.50%) |
Fire Victim Trust | (1.609) | 1.273 | (0.449) |
Bankruptcy and emergence | 0% | 0% | (37.60%) |
Other, net | 12.90% | 5.30% | (2.10%) |
Effective tax rate | (329.80%) | 111.70% | (38.40%) |
INCOME TAXES (Schedule of Chang
INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pacific Gas & Electric Co (Utility) | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | $ 498 | $ 437 | $ 420 |
Reductions for tax position taken during a prior year | (1) | (23) | (43) |
Additions for tax position taken during the current year | 73 | 85 | 60 |
Settlements | 0 | (1) | 0 |
Balance, end of period | 570 | 498 | 437 |
PG&E Corporation | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, beginning of period | 498 | 437 | 420 |
Reductions for tax position taken during a prior year | (1) | (23) | (43) |
Additions for tax position taken during the current year | 73 | 85 | 60 |
Settlements | 0 | (1) | 0 |
Balance, end of period | $ 570 | $ 498 | $ 437 |
INCOME TAXES (Narrative) (Detai
INCOME TAXES (Narrative) (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Feb. 16, 2023 | Jan. 09, 2023 | Jan. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Investments, Owned, Federal Income Tax Note [Line Items] | ||||||
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year | $ 31 | |||||
Equity securities ownership, threshold | 4.75% | |||||
Income tax provision (benefit) | $ (1,338) | $ 836 | $ 362 | |||
Fire Victim Trust | ||||||
Investments, Owned, Federal Income Tax Note [Line Items] | ||||||
Shares sold, tax impact | $ 870 | |||||
Number of shares exchanged (in shares) | 230 | |||||
Fire Victim Trust | Subsequent Event | ||||||
Investments, Owned, Federal Income Tax Note [Line Items] | ||||||
Number of shares sold (in shares) | 290 | |||||
Number of shares exchanged (in shares) | 60 | |||||
Income tax provision (benefit) | $ (256) |
INCOME TAXES (Summary of Operat
INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Federal | |
Operating Loss Carryforwards [Line Items] | |
Tax credit carryforward | $ 152 |
Federal | Pre-2018 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 3,447 |
Federal | Post-2017 | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 23,170 |
State | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforward | 25,169 |
Tax credit carryforward | $ 126 |
DERIVATIVES (Narrative) (Detail
DERIVATIVES (Narrative) (Details) | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative Asset, Statement of Financial Position [Extensible Enumeration] | Regulatory assets | Regulatory assets |
DERIVATIVES (Volumes of Outstan
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details) | Dec. 31, 2022 MWh MMBTU | Dec. 31, 2021 MWh MMBTU |
Forwards, Futures and Swaps | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | 171,212,813 | 173,361,635 |
Forwards, Futures and Swaps | Electricity (MWh) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 10,814,728 | 10,283,639 |
Options | Natural Gas (MMBtus) | ||
Derivative [Line Items] | ||
Contract Volume | 27,785,000 | 14,420,000 |
Options | Electricity (MWh) | ||
Derivative [Line Items] | ||
Contract Volume | 215,600 | 288,000 |
Congestion revenue rights | Electricity (MWh) | ||
Derivative [Line Items] | ||
Contract Volume | MWh | 205,743,505 | 239,857,610 |
DERIVATIVES (Outstanding Deriva
DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Contract - Pacific Gas & Electric Co (Utility) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Derivatives And Hedging Activities [Line Items] | ||
Netting | $ 715 | $ (42) |
Netting | 0 | 0 |
Cash Collateral | 553 | 170 |
Total Derivative Balance | 1,268 | 128 |
Current assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 824 | 58 |
Netting | (170) | (9) |
Cash Collateral | 537 | 152 |
Total Derivative Balance | 1,191 | 201 |
Other noncurrent assets – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 306 | 169 |
Netting | 0 | 0 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 306 | 169 |
Current liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (238) | (53) |
Netting | 170 | 9 |
Cash Collateral | 16 | 18 |
Total Derivative Balance | (52) | (26) |
Noncurrent liabilities – other | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (177) | (216) |
Netting | 0 | 0 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | $ (177) | $ (216) |
FAIR VALUE MEASUREMENTS (Assets
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Assets: | ||
Short-term investments | $ 289 | |
Price risk management instruments, netting | $ 367 | 143 |
Price risk management instruments, assets | 1,497 | 370 |
TOTAL ASSETS | 7,127 | 5,558 |
Liabilities: | ||
Price risk management instruments, netting | (186) | (27) |
TOTAL LIABILITIES | 229 | 242 |
Amount primarily related to deferred taxes on appreciation of investment value | 575 | 783 |
Short-term investments | ||
Assets: | ||
Short-term investments | 658 | |
Fixed-income securities | ||
Assets: | ||
Short-term investments | 49 | |
Nuclear decommissioning trusts | ||
Assets: | ||
Short-term investments | 117 | 22 |
Global equity securities | 1,845 | 2,504 |
Fixed-income securities | 1,885 | 2,024 |
TOTAL ASSETS | 3,872 | 4,581 |
Customer credit trust | ||
Assets: | ||
Short-term investments | 19 | |
Global equity securities | 218 | |
Fixed-income securities | 508 | |
TOTAL ASSETS | 745 | |
Rabbi trusts | ||
Assets: | ||
Short-term investments | 25 | |
Global equity securities | 5 | |
Fixed-income securities | 69 | 104 |
Life insurance contracts | 64 | 76 |
TOTAL ASSETS | 163 | 180 |
Long-term disability trust | ||
Assets: | ||
Short-term investments | 10 | 6 |
TOTAL ASSETS | 143 | 138 |
Price Risk Derivative, Electricity | ||
Assets: | ||
Price risk management instruments, netting | 40 | 6 |
Price risk management instruments, assets | 566 | 229 |
Liabilities: | ||
Price risk management instruments, netting | (20) | (24) |
Price risk management instruments, liabilities | 223 | 235 |
Price Risk Derivative, Gas | ||
Assets: | ||
Price risk management instruments, netting | 327 | 137 |
Price risk management instruments, assets | 931 | 141 |
Liabilities: | ||
Price risk management instruments, netting | (166) | (3) |
Price risk management instruments, liabilities | 6 | 7 |
Level 1 | ||
Assets: | ||
Short-term investments | 289 | |
Price risk management instruments, gross subject to netting | 0 | 0 |
TOTAL ASSETS | 4,207 | 3,979 |
Liabilities: | ||
TOTAL LIABILITIES | 0 | 0 |
Level 1 | Short-term investments | ||
Assets: | ||
Short-term investments | 658 | |
Level 1 | Fixed-income securities | ||
Assets: | ||
Short-term investments | 0 | |
Level 1 | Nuclear decommissioning trusts | ||
Assets: | ||
Short-term investments | 117 | 22 |
Global equity securities | 1,845 | 2,504 |
Fixed-income securities | 1,094 | 1,158 |
TOTAL ASSETS | 3,056 | 3,684 |
Level 1 | Customer credit trust | ||
Assets: | ||
Short-term investments | 19 | |
Global equity securities | 218 | |
Fixed-income securities | 216 | |
TOTAL ASSETS | 453 | |
Level 1 | Rabbi trusts | ||
Assets: | ||
Short-term investments | 25 | |
Global equity securities | 5 | |
Fixed-income securities | 0 | 0 |
Life insurance contracts | 0 | 0 |
TOTAL ASSETS | 30 | 0 |
Level 1 | Long-term disability trust | ||
Assets: | ||
Short-term investments | 10 | 6 |
TOTAL ASSETS | 10 | 6 |
Level 1 | Price Risk Derivative, Electricity | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Level 1 | Price Risk Derivative, Gas | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Level 2 | ||
Assets: | ||
Short-term investments | 0 | |
Price risk management instruments, gross subject to netting | 698 | 13 |
TOTAL ASSETS | 1,963 | 1,059 |
Liabilities: | ||
TOTAL LIABILITIES | 182 | 21 |
Level 2 | Short-term investments | ||
Assets: | ||
Short-term investments | 0 | |
Level 2 | Fixed-income securities | ||
Assets: | ||
Short-term investments | 49 | |
Level 2 | Nuclear decommissioning trusts | ||
Assets: | ||
Short-term investments | 0 | 0 |
Global equity securities | 0 | 0 |
Fixed-income securities | 791 | 866 |
TOTAL ASSETS | 791 | 866 |
Level 2 | Customer credit trust | ||
Assets: | ||
Short-term investments | 0 | |
Global equity securities | 0 | |
Fixed-income securities | 292 | |
TOTAL ASSETS | 292 | |
Level 2 | Rabbi trusts | ||
Assets: | ||
Short-term investments | 0 | |
Global equity securities | 0 | |
Fixed-income securities | 69 | 104 |
Life insurance contracts | 64 | 76 |
TOTAL ASSETS | 133 | 180 |
Level 2 | Long-term disability trust | ||
Assets: | ||
Short-term investments | 0 | 0 |
TOTAL ASSETS | 0 | 0 |
Level 2 | Price Risk Derivative, Electricity | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 94 | 9 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 10 | 11 |
Level 2 | Price Risk Derivative, Gas | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 604 | 4 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 172 | 10 |
Level 3 | ||
Assets: | ||
Short-term investments | 0 | |
Price risk management instruments, gross subject to netting | 432 | 214 |
TOTAL ASSETS | 432 | 214 |
Liabilities: | ||
TOTAL LIABILITIES | 233 | 248 |
Level 3 | Short-term investments | ||
Assets: | ||
Short-term investments | 0 | |
Level 3 | Fixed-income securities | ||
Assets: | ||
Short-term investments | 0 | |
Level 3 | Nuclear decommissioning trusts | ||
Assets: | ||
Short-term investments | 0 | 0 |
Global equity securities | 0 | 0 |
Fixed-income securities | 0 | 0 |
TOTAL ASSETS | 0 | 0 |
Level 3 | Customer credit trust | ||
Assets: | ||
Short-term investments | 0 | |
Global equity securities | 0 | |
Fixed-income securities | 0 | |
TOTAL ASSETS | 0 | |
Level 3 | Rabbi trusts | ||
Assets: | ||
Short-term investments | 0 | |
Global equity securities | 0 | |
Fixed-income securities | 0 | 0 |
Life insurance contracts | 0 | 0 |
TOTAL ASSETS | 0 | 0 |
Level 3 | Long-term disability trust | ||
Assets: | ||
Short-term investments | 0 | 0 |
TOTAL ASSETS | 0 | 0 |
Level 3 | Price Risk Derivative, Electricity | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 432 | 214 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 233 | 248 |
Level 3 | Price Risk Derivative, Gas | ||
Assets: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Liabilities: | ||
Price risk management instruments, gross subject to netting | 0 | 0 |
Fair Value Measured at Net Asset Value Per Share | Nuclear decommissioning trusts | ||
Assets: | ||
Assets measured at NAV | 25 | 31 |
Fair Value Measured at Net Asset Value Per Share | Long-term disability trust | ||
Assets: | ||
Assets measured at NAV | $ 133 | $ 132 |
FAIR VALUE MEASUREMENTS (Level
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions | Dec. 31, 2022 USD ($) $ / shares | Dec. 31, 2021 USD ($) $ / shares |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | $ 1,497 | $ 370 |
Market approach | Congestion revenue rights | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | 305 | 188 |
Liabilities | $ | 138 | 93 |
Discounted cash flow | Power purchase agreements | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Assets | $ | 127 | 26 |
Liabilities | $ | $ 95 | $ 155 |
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) | (145.09) | (40.77) |
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) | 2,724.93 | 2,265.94 |
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) | 0.89 | 0.40 |
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) | (6.39) | (7.97) |
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) | 286.75 | 256.20 |
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) | 78.14 | 47.17 |
FAIR VALUE MEASUREMENTS (Leve_2
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||
Asset (Liability) balance, beginning of period | $ (34) | $ (72) |
Included in regulatory assets and liabilities or balancing accounts | 233 | 38 |
Asset (Liability) balance, end of period | $ 199 | $ (34) |
FAIR VALUE MEASUREMENTS (Carryi
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Carrying Amount | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | $ 4,355 | $ 4,619 |
Carrying Amount | Pacific Gas & Electric Co (Utility) | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 32,847 | 31,816 |
Level 2 | Fair Value | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | 4,490 | 4,796 |
Level 2 | Fair Value | Pacific Gas & Electric Co (Utility) | ||
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||
Debt financial instrument | $ 27,666 | $ 35,803 |
FAIR VALUE MEASUREMENTS (Schedu
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Securities, Available-for-sale [Line Items] | ||
Amount primarily related to deferred taxes on appreciation of investment value | $ 575 | $ 783 |
Nuclear decommissioning trusts | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 2,521 | 2,439 |
Total Unrealized Gains | 1,478 | 2,164 |
Total Unrealized Losses | (127) | (22) |
Total Fair Value | 3,872 | 4,581 |
Nuclear decommissioning trusts | Short-term investments | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 117 | 22 |
Total Unrealized Gains | 0 | 0 |
Total Unrealized Losses | 0 | 0 |
Total Fair Value | 117 | 22 |
Nuclear decommissioning trusts | Global equity securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 413 | 479 |
Total Unrealized Gains | 1,468 | 2,066 |
Total Unrealized Losses | (11) | (10) |
Total Fair Value | 1,870 | 2,535 |
Nuclear decommissioning trusts | Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 1,991 | 1,938 |
Total Unrealized Gains | 10 | 98 |
Total Unrealized Losses | (116) | (12) |
Total Fair Value | 1,885 | $ 2,024 |
Customer credit trust | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 754 | |
Total Unrealized Gains | 13 | |
Total Unrealized Losses | (22) | |
Total Fair Value | 745 | |
Customer credit trust | Short-term investments | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 19 | |
Total Unrealized Gains | 0 | |
Total Unrealized Losses | 0 | |
Total Fair Value | 19 | |
Customer credit trust | Global equity securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 219 | |
Total Unrealized Gains | 13 | |
Total Unrealized Losses | (14) | |
Total Fair Value | 218 | |
Customer credit trust | Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Amortized Cost | 516 | |
Total Unrealized Gains | 0 | |
Total Unrealized Losses | (8) | |
Total Fair Value | $ 508 |
FAIR VALUE MEASUREMENTS (Sche_2
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Nuclear decommissioning trusts | ||
Debt Securities, Available-for-sale [Line Items] | ||
Total maturities of fixed-income securities | $ 3,872 | $ 4,581 |
Nuclear decommissioning trusts | Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Less than 1 year | 42 | |
1–5 years | 624 | |
5–10 years | 400 | |
More than 10 years | 819 | |
Total maturities of fixed-income securities | 1,885 | $ 2,024 |
Customer credit trust | ||
Debt Securities, Available-for-sale [Line Items] | ||
Total maturities of fixed-income securities | 745 | |
Customer credit trust | Fixed-income securities | ||
Debt Securities, Available-for-sale [Line Items] | ||
Less than 1 year | 79 | |
1–5 years | 123 | |
5–10 years | 120 | |
More than 10 years | 186 | |
Total maturities of fixed-income securities | $ 508 |
FAIR VALUE MEASUREMENTS (Sche_3
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 3,316 | $ 1,678 | $ 1,518 |
Impairment loss | 6 | ||
Nuclear decommissioning trusts | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | 3,316 | 1,678 | 1,518 |
Gross realized gains on securities | 2 | 286 | 159 |
Gross realized losses on securities | (3) | $ (19) | $ (41) |
Customer credit trust | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Proceeds from sales and maturities of nuclear decommissioning trust investments | 250 | ||
Gross realized gains on securities | 10 | ||
Gross realized losses on securities | $ (41) |
EMPLOYEE BENEFIT PLANS (Reconci
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Funded Status: | |||
Noncurrent liability | $ (231) | $ (860) | |
Pension Plan | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 21,895 | 20,759 | |
Actual return on plan assets | (4,916) | 1,693 | |
Company contributions | 339 | 335 | |
Benefits and expenses paid | (949) | (892) | |
Fair value of plan assets at end of year | 16,369 | 21,895 | $ 20,759 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 22,759 | 23,172 | |
Service cost for benefits earned | 575 | 587 | 530 |
Interest cost | 692 | 645 | 713 |
Actuarial gain | (6,471) | (752) | |
Plan amendments | 0 | 0 | |
Benefits and expenses paid | (947) | (893) | |
Benefit obligation at end of year | 16,608 | 22,759 | 23,172 |
Funded Status: | |||
Current liability | (8) | (9) | |
Noncurrent liability | (231) | (856) | |
Net (liability) asset at end of year | (239) | (865) | |
Accumulated benefit obligation | 15,400 | 20,400 | |
PBOP Plans | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 3,102 | 2,995 | |
Actual return on plan assets | (693) | 193 | |
Company contributions | 26 | 10 | |
Plan participant contribution | 81 | 80 | |
Benefits and expenses paid | (180) | (176) | |
Fair value of plan assets at end of year | 2,336 | 3,102 | 2,995 |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 1,766 | 1,876 | |
Service cost for benefits earned | 62 | 63 | 61 |
Interest cost | 53 | 51 | 63 |
Actuarial gain | (486) | (152) | |
Benefits and expenses paid | (162) | (156) | |
Federal subsidy on benefits paid | 3 | 4 | |
Plan participant contributions | 81 | 80 | |
VSP related termination benefits | 22 | 0 | |
Benefit obligation at end of year | 1,339 | 1,766 | $ 1,876 |
Funded Status: | |||
Noncurrent asset | 997 | 1,340 | |
Noncurrent liability | 0 | (4) | |
Net (liability) asset at end of year | 997 | 1,336 | |
PBOP Plans | Postretirement Life Insurance Plan | |||
Change in plan assets: | |||
Fair value of plan assets at beginning of year | 359 | ||
Fair value of plan assets at end of year | 266 | 359 | |
Change in benefit obligation: | |||
Benefit obligation at beginning of year | 363 | ||
Benefit obligation at end of year | $ 259 | $ 363 |
EMPLOYEE BENEFIT PLANS (Compone
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | $ 575 | $ 587 | $ 530 |
Interest cost | 692 | 645 | 713 |
Expected return on plan assets | (1,189) | (1,046) | (1,044) |
Amortization of prior service cost | (4) | (6) | (6) |
Amortization of net actuarial loss | 2 | 6 | 3 |
Net periodic benefit cost | 76 | 186 | 196 |
Less: transfer to regulatory account | 254 | 147 | 136 |
Total expense recognized | 330 | 333 | 332 |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | 62 | 63 | 61 |
Interest cost | 53 | 51 | 63 |
Expected return on plan assets | (130) | (137) | (138) |
Amortization of prior service cost | 7 | 14 | 14 |
Amortization of net actuarial loss | (40) | (33) | (21) |
Special termination benefits | 22 | 0 | 0 |
Net periodic benefit cost | $ (26) | $ (42) | $ (21) |
EMPLOYEE BENEFIT PLANS (Schedul
EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Expected return on plan assets | 5.80% | ||
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 5.54% | 3.03% | 2.77% |
Rate of future compensation increases | 3.80% | 3.80% | 3.80% |
Expected return on plan assets | 6.10% | 5.50% | 5.10% |
Interest crediting rate for cash balance plan | 4.19% | 1.95% | 1.95% |
PBOP Plans | Minimum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 5.50% | 2.97% | 2.67% |
Expected return on plan assets | 3.70% | 3.30% | 3.10% |
PBOP Plans | Maximum | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 5.54% | 3.04% | 2.80% |
Expected return on plan assets | 7.30% | 6.40% | 6.10% |
EMPLOYEE BENEFIT PLANS (Narrati
EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 USD ($) noncallable_bond | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |||
Assumed health care cost trend rate | 6.50% | ||
Ultimate trend rate | 4.50% | ||
Assumed return | 6.10% | ||
10 year actual rate of return | 5.80% | ||
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond | 848 | ||
Total fair value of trust other net liabilities | $ 11 | $ 175 | |
Retirement savings plan expense | $ 144 | $ 133 | $ 119 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
10 year actual rate of return | 6.10% | 5.50% | 5.10% |
Company contributions | $ 339 | $ 335 | |
Expected employer contribution next year | 327 | ||
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Company contributions | $ 26 | $ 10 |
EMPLOYEE BENEFIT PLANS (Target
EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details) | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100% | 100% | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 30% | 30% | |
Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 2% | 2% | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8% | 8% | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 60% | 60% | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100% | 100% | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 26% | 36% | |
PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 1% | 1% | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 3% | 5% | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 70% | 58% | |
Forecast | Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100% | ||
Forecast | Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 26% | ||
Forecast | Pension Plan | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 1% | ||
Forecast | Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 8% | ||
Forecast | Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 65% | ||
Forecast | PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 100% | ||
Forecast | PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 28% | ||
Forecast | PBOP Plans | Absolute return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 1% | ||
Forecast | PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 3% | ||
Forecast | PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total target asset allocation | 68% |
EMPLOYEE BENEFIT PLANS (Sched_2
EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | $ 18,716 | $ 25,172 | |
Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 8 | 27 | $ 12 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 16,369 | 22,054 | |
Assets measured at NAV | 16,369 | 21,895 | 20,759 |
Pension Plan | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 587 | 807 | |
Pension Plan | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,430 | 2,498 | |
Pension Plan | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 1 | |
Pension Plan | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 426 | 632 | |
Pension Plan | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 8,040 | 10,144 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 4,263 | 5,987 | |
Pension Plan | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 461 | 552 | |
Pension Plan | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,430 | 2,074 | |
Pension Plan | Level 1 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 426 | 632 | |
Pension Plan | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,946 | 2,729 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 6,212 | 8,068 | |
Pension Plan | Level 2 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 126 | 255 | |
Pension Plan | Level 2 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 424 | |
Pension Plan | Level 2 | Absolute Return | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 1 | |
Pension Plan | Level 2 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 0 | 0 | |
Pension Plan | Level 2 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 6,086 | 7,388 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 8 | 27 | |
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 | 8 | 27 | |
Pension Plan | Fair Value Measured at Net Asset Value Per Share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | 5,886 | 7,972 | |
PBOP Plans | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 2,347 | 3,118 | |
Assets measured at NAV | 2,336 | 3,102 | $ 2,995 |
PBOP Plans | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 26 | 31 | |
PBOP Plans | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 83 | 105 | |
PBOP Plans | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 29 | 34 | |
PBOP Plans | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 1,109 | 1,652 | |
PBOP Plans | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 544 | 946 | |
PBOP Plans | Level 1 | Short-term investments | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 26 | 31 | |
PBOP Plans | Level 1 | Global equity securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 83 | 105 | |
PBOP Plans | Level 1 | Real assets | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 29 | 34 | |
PBOP Plans | Level 1 | Fixed-income securities | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 406 | 776 | |
PBOP Plans | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total plan assets at fair value | 702 | 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 | 702 | 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 | Fair Value Measured at Net Asset Value Per Share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Assets measured at NAV | $ 1,100 | $ 1,296 |
EMPLOYEE BENEFIT PLANS (Sched_3
EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Fair value of plan assets at beginning of year | $ 27 | $ 12 |
Actual return on plan assets: | ||
Relating to assets still held at the reporting date | 1 | 6 |
Relating to assets sold during the period | 0 | (7) |
Purchases, issuances, sales, and settlements: | ||
Purchases | 6 | 22 |
Settlements | (26) | (6) |
Fair value of plan assets at end of year | $ 8 | $ 27 |
EMPLOYEE BENEFIT PLANS (Sched_4
EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Pension Plan | |
Defined Benefit Plan Disclosure [Line Items] | |
2023 | $ 907 |
2024 | 996 |
2025 | 1,028 |
2026 | 1,057 |
2027 | 1,082 |
Thereafter in the succeeding five years | 5,702 |
PBOP Plans | |
Defined Benefit Plan Disclosure [Line Items] | |
2023 | 97 |
2024 | 98 |
2025 | 100 |
2026 | 94 |
2027 | 94 |
Thereafter in the succeeding five years | 475 |
Federal Subsidy | |
Defined Benefit Plan Disclosure [Line Items] | |
2023 | (4) |
2024 | (4) |
2025 | (4) |
2026 | (4) |
2027 | (4) |
Thereafter in the succeeding five years | $ (4) |
RELATED PARTY AGREEMENTS AND _3
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, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Administrative services provided to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility revenues from | $ 3 | $ 3 | $ 3 |
Administrative services received from PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | 104 | 82 | 108 |
Utility employee benefit due to PG&E Corporation | |||
Related Party Transaction [Line Items] | |||
Utility expenses from | $ 85 | $ 39 | $ 34 |
RELATED PARTY AGREEMENTS AND _4
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - USD ($) $ in Millions | Aug. 11, 2021 | Dec. 31, 2022 | Dec. 31, 2021 |
Related Party Transaction [Line Items] | |||
Intercompany note to PG&E Corporation | $ 145 | ||
Pacific Gas & Electric Co (Utility) | |||
Related Party Transaction [Line Items] | |||
Current receivables | $ 33 | $ 173 | |
Current payables | $ 46 | $ 19 |
WILDFIRE-RELATED CONTINGENCIE_2
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2020 Zogg Fire, 2021 Dixie Fire and 2022 Mosquito Fire) (Details) $ in Thousands, numberOfPeople in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||
Feb. 21, 2023 USD ($) | Oct. 25, 2022 USD ($) | Mar. 18, 2022 USD ($) | Jan. 05, 2022 USD ($) | Oct. 29, 2021 USD ($) a | Nov. 04, 2019 numberOfPeople | Mar. 31, 2022 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | Feb. 16, 2023 plaintiff complaint notice numberOfPlaintiff numberOfClaimHolder | Feb. 03, 2023 notice | Jan. 17, 2023 USD ($) | Sep. 30, 2022 USD ($) | Sep. 06, 2022 a injury numberOfFatality structure | Aug. 31, 2022 USD ($) | Jul. 14, 2022 transmissionLine | Jun. 09, 2022 notice | Apr. 28, 2022 USD ($) | Apr. 11, 2022 USD ($) position | Apr. 08, 2022 USD ($) position | Jan. 28, 2022 notice | Jan. 27, 2022 notice | Nov. 18, 2021 notice | Sep. 30, 2021 USD ($) | Sep. 24, 2021 misdemeanor felony | Jul. 13, 2021 a structure injury | Apr. 06, 2021 misdemeanor felony | Sep. 27, 2020 a injury fatality structure | Oct. 23, 2019 a structure numberOfFatality injury | |
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Amount expected to pay | $ 477,000 | $ 517,000 | $ 413,000 | |||||||||||||||||||||||||||
Accrued insurance recoveries | 45,000 | |||||||||||||||||||||||||||||
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 structures damaged (structure) | structure | 60 | |||||||||||||||||||||||||||||
Number of people part of mandatory evacuation order | numberOfPeople | 0.2 | |||||||||||||||||||||||||||||
Number of felonies (felony) | notice | 5 | 2 | ||||||||||||||||||||||||||||
Number of misdemeanors dropped (misdemeanor) | notice | 6 | |||||||||||||||||||||||||||||
Stipulation costs payable | $ 20,250 | |||||||||||||||||||||||||||||
Number of new positions headquartered (position) | position | 80 | |||||||||||||||||||||||||||||
Stipulation costs paid | 5,450 | |||||||||||||||||||||||||||||
Number of transmission lines | transmissionLine | 70 | |||||||||||||||||||||||||||||
Payments | 344,000 | |||||||||||||||||||||||||||||
Fire fighting costs recovery requested | $ 90,000 | |||||||||||||||||||||||||||||
Potential loss contingency | 1,025,000 | 800,000 | ||||||||||||||||||||||||||||
Accrued Losses | 225,000 | |||||||||||||||||||||||||||||
Insurance receivable | 430,000 | |||||||||||||||||||||||||||||
Accrued insurance recoveries | 0 | |||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||
Payments | 204,000 | |||||||||||||||||||||||||||||
Potential loss contingency | 400,000 | 375,000 | ||||||||||||||||||||||||||||
Accrued Losses | 25,000 | |||||||||||||||||||||||||||||
Insurance receivable | 370,000 | |||||||||||||||||||||||||||||
Number of demurrer filed (count) | notice | 10 | |||||||||||||||||||||||||||||
Number of criminal complaints (count) | notice | 31 | |||||||||||||||||||||||||||||
Number of criminal complaints dismissed (count) | notice | 20 | |||||||||||||||||||||||||||||
Penalty recommended | $ 155,000 | |||||||||||||||||||||||||||||
Litigation liability, payment accrual | 10,000 | |||||||||||||||||||||||||||||
Fire suppression and other costs | $ 34,500 | |||||||||||||||||||||||||||||
Potential loss contingency, additional | 25,000 | |||||||||||||||||||||||||||||
Liability insurance coverage | 611,000 | |||||||||||||||||||||||||||||
Initial self-insured retention per occurrence | 60,000 | |||||||||||||||||||||||||||||
Legal fees | 30,000 | |||||||||||||||||||||||||||||
Accrued insurance recoveries | 33,000 | |||||||||||||||||||||||||||||
Zogg Complaint, 2020 | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of felonies (felony) | felony | 11 | |||||||||||||||||||||||||||||
Number of misdemeanors (misdemeanor) | misdemeanor | 20 | |||||||||||||||||||||||||||||
Insurance Coverage for Wildfire Events | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Liability insurance coverage | $ 600,000 | $ 340,000 | ||||||||||||||||||||||||||||
Initial self-insured retention per occurrence | 60,000 | |||||||||||||||||||||||||||||
2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of acres burned (acre) | a | 963,309 | |||||||||||||||||||||||||||||
Number of structures destroyed (structure) | structure | 1,311 | |||||||||||||||||||||||||||||
Number of structures damaged (structure) | structure | 94 | |||||||||||||||||||||||||||||
Stipulation costs payable | $ 34,750 | |||||||||||||||||||||||||||||
Number of new positions headquartered (position) | position | 80 | |||||||||||||||||||||||||||||
Loss contingency liability | 1,175,000 | |||||||||||||||||||||||||||||
Loss contingency, costs incurred | $ 650,000 | |||||||||||||||||||||||||||||
Payments | 44,000 | |||||||||||||||||||||||||||||
Potential loss contingency | 1,150,000 | |||||||||||||||||||||||||||||
Accrued Losses | 25,000 | |||||||||||||||||||||||||||||
Insurance receivable | 530,000 | |||||||||||||||||||||||||||||
Liability insurance coverage | 900,000 | |||||||||||||||||||||||||||||
Number of residential structures destroyed (structure) | structure | 763 | |||||||||||||||||||||||||||||
Number of multi-family residential structures destroyed (structure) | structure | 12 | |||||||||||||||||||||||||||||
Number of commercial residential structures destroyed (structure) | structure | 8 | |||||||||||||||||||||||||||||
Number of commercial non-residential structures destroyed (structure) | structure | 148 | |||||||||||||||||||||||||||||
Number of detached structures destroyed (structure) | structure | 466 | |||||||||||||||||||||||||||||
Number of first responder injuries (injury) | injury | 4 | |||||||||||||||||||||||||||||
Probable of recovery | 1,208,000 | |||||||||||||||||||||||||||||
Accrued insurance recoveries | (33,000) | |||||||||||||||||||||||||||||
Dixie Stipulation | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Payments | 30,750 | |||||||||||||||||||||||||||||
2022 Mosquito fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of acres burned (acre) | a | 76,788 | |||||||||||||||||||||||||||||
Number of fatalities (fatality) | numberOfFatality | 0 | |||||||||||||||||||||||||||||
Number of injuries | injury | 0 | |||||||||||||||||||||||||||||
Number of structures destroyed (structure) | structure | 78 | |||||||||||||||||||||||||||||
Number of structures damaged (structure) | structure | 13 | |||||||||||||||||||||||||||||
Loss contingency liability | $ 100,000 | |||||||||||||||||||||||||||||
Liability insurance coverage | 940,000 | |||||||||||||||||||||||||||||
Probable of recovery | 105,000 | |||||||||||||||||||||||||||||
Percentage of fire contained | 100% | |||||||||||||||||||||||||||||
Accrued insurance recoveries | 45,000 | |||||||||||||||||||||||||||||
Subsequent Event | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Settlement amount proposed | $ 24,000 | |||||||||||||||||||||||||||||
Subsequent Event | 2019 Kincade fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of complaints (complaint) | complaint | 113 | |||||||||||||||||||||||||||||
Number of plaintiffs represented by complaints | plaintiff | 2,720 | |||||||||||||||||||||||||||||
Subsequent Event | 2020 Zogg fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of complaints (complaint) | complaint | 29 | |||||||||||||||||||||||||||||
Number of plaintiffs represented by complaints | numberOfPlaintiff | 523 | |||||||||||||||||||||||||||||
Number of criminal complaints (count) | notice | 11 | |||||||||||||||||||||||||||||
Costs unable to recover | $ 140,000 | |||||||||||||||||||||||||||||
Subsequent Event | 2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of complaints (complaint) | numberOfClaimHolder | 81 | |||||||||||||||||||||||||||||
Number of plaintiffs represented by complaints | numberOfClaimHolder | 2,094 | |||||||||||||||||||||||||||||
Subsequent Event | 2022 Mosquito fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of complaints (complaint) | complaint | 6 | |||||||||||||||||||||||||||||
Number of plaintiffs represented by complaints | notice | 236 | |||||||||||||||||||||||||||||
FERC TO rates | 2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Probable of recovery | 115,000 | |||||||||||||||||||||||||||||
FERC TO rates | 2022 Mosquito fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Probable of recovery | 10,000 | |||||||||||||||||||||||||||||
WEMA | 2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Probable of recovery | 388,000 | |||||||||||||||||||||||||||||
Increase in regulatory asset | 41,000 | |||||||||||||||||||||||||||||
WEMA | 2022 Mosquito fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Probable of recovery | 50,000 | |||||||||||||||||||||||||||||
National Park | 2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of acres burned (acre) | a | 70,000 | |||||||||||||||||||||||||||||
National Forrest | 2021 Dixie fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of acres burned (acre) | a | 685,000 | |||||||||||||||||||||||||||||
California General Fund | Subsequent Event | 2020 Zogg fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Amount expected to pay | $ 10,000 | |||||||||||||||||||||||||||||
Pacific Gas & Electric Co (Utility) | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Amount expected to pay | 477,000 | $ 517,000 | $ 413,000 | |||||||||||||||||||||||||||
Pacific Gas & Electric Co (Utility) | 2019 Kincade fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Loss contingency liability | $ 40,000 | |||||||||||||||||||||||||||||
Loss contingency, costs incurred | $ 85,000 | 85,000 | ||||||||||||||||||||||||||||
Pacific Gas & Electric Co (Utility) | Sonoma Contry District Attorney | 2019 Kincade fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Number of felonies (felony) | felony | 5 | |||||||||||||||||||||||||||||
Number of misdemeanors (misdemeanor) | misdemeanor | 28 | |||||||||||||||||||||||||||||
Pacific Gas & Electric Co (Utility) | California General Fund | 2019 Kincade fire | ||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||
Payments | $ 20,000 |
WILDFIRE-RELATED CONTINGENCIE_3
WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
2019 Kincade fire | |
Loss Contingency Accrual [Roll Forward] | |
Loss accrual, beginning balance | $ 769 |
Accrued Losses | 225 |
Payments | (344) |
Loss accrual, ending balance | 650 |
2020 Zogg fire | |
Loss Contingency Accrual [Roll Forward] | |
Loss accrual, beginning balance | 211 |
Accrued Losses | 25 |
Payments | (204) |
Loss accrual, ending balance | 32 |
2021 Dixie fire | |
Loss Contingency Accrual [Roll Forward] | |
Loss accrual, beginning balance | 1,150 |
Accrued Losses | 25 |
Payments | (44) |
Loss accrual, ending balance | $ 1,131 |
WILDFIRE-RELATED CONTINGENCIE_4
WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | $ 105 |
2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 1,208 |
Insurance | 2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 45 |
Insurance | 2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 530 |
WEMA | 2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 50 |
WEMA | 2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 388 |
Wildfire Fund | 2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 0 |
Wildfire Fund | 2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 175 |
FERC TO rates | 2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 10 |
FERC TO rates | 2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | $ 115 |
WILDFIRE-RELATED CONTINGENCIE_5
WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Apr. 28, 2022 | Aug. 01, 2023 | Apr. 01, 2023 | Dec. 31, 2022 | Aug. 31, 2022 | |
Loss Contingencies [Line Items] | |||||
Insurance premium costs, recovery, coverage amount | $ 1,400 | ||||
Insurance Coverage for Wildfire Events | |||||
Loss Contingencies [Line Items] | |||||
Liability insurance coverage | $ 340 | $ 600 | |||
Initial self-insured retention per occurrence | 60 | ||||
Insurance Coverage for Wildfire Events | Forecast | |||||
Loss Contingencies [Line Items] | |||||
Costs for insurance coverage | $ 516 | $ 263 | |||
Insurance Coverage For Non-Wildfire Liabilities | |||||
Loss Contingencies [Line Items] | |||||
Liability insurance coverage | 725 | ||||
Costs for insurance coverage | $ 154 | ||||
Initial self-insured retention per occurrence | 10 | ||||
Prepaid insurance | $ 424 |
WILDFIRE-RELATED CONTINGENCIE_6
WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | $ 1,247 |
Accrued insurance recoveries | 45 |
Reimbursements | (498) |
Insurance Receivable, Ending Balance | 794 |
Resolved claims | 418 |
Other Receivables | |
Insurance Receivable [Roll Forward] | |
Resolved claims | 13 |
2022 Mosquito fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 0 |
Accrued insurance recoveries | 45 |
Reimbursements | 0 |
Insurance Receivable, Ending Balance | 45 |
2021 Dixie fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 563 |
Accrued insurance recoveries | (33) |
Reimbursements | 0 |
Insurance Receivable, Ending Balance | 530 |
Insurance receivable | 530 |
2020 Zogg fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 270 |
Accrued insurance recoveries | 33 |
Reimbursements | (185) |
Insurance Receivable, Ending Balance | 118 |
Insurance receivable | 370 |
2019 Kincade fire | |
Insurance Receivable [Roll Forward] | |
Insurance Receivable, Beginning Balance | 414 |
Accrued insurance recoveries | 0 |
Reimbursements | (313) |
Insurance Receivable, Ending Balance | 101 |
Insurance receivable | $ 430 |
WILDFIRE-RELATED CONTINGENCIE_7
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
2021 Dixie fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | $ 1,208 |
2021 Dixie fire | FERC TO rates | |
Loss Contingencies [Line Items] | |
Probable of recovery | 115 |
2021 Dixie fire | WEMA | |
Loss Contingencies [Line Items] | |
Probable of recovery | 388 |
2022 Mosquito fire | |
Loss Contingencies [Line Items] | |
Probable of recovery | 105 |
2022 Mosquito fire | FERC TO rates | |
Loss Contingencies [Line Items] | |
Probable of recovery | 10 |
2022 Mosquito fire | WEMA | |
Loss Contingencies [Line Items] | |
Probable of recovery | $ 50 |
WILDFIRE-RELATED CONTINGENCIE_8
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Aug. 23, 2019 | Dec. 31, 2022 | |
Loss Contingencies [Line Items] | ||
Disallowance cap, transmission and distribution 2022 equity rate base | $ 3,000 | |
Initial safety certification, documentation provided, period | 90 days | |
Initial safety certification, period | 12 months | |
Expected capitalization, proceeds of bond | 10,500 | |
Expected capitalization, initial contribution | 7,500 | |
Expected capitalization, annual contribution | 300 | |
2021 Dixie fire | ||
Loss Contingencies [Line Items] | ||
Probable of recovery | 1,208 | |
2021 Dixie fire | Wildfire Fund | ||
Loss Contingencies [Line Items] | ||
Probable of recovery | $ 175 |
WILDFIRE-RELATED CONTINGENCIE_9
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Claims, Fire Victim Trust D&O Claims and Related Insurance Recoveries Overview) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Jul. 26, 2022 | |
Loss Contingencies [Line Items] | ||||
Net Income (Loss) | $ (1,814) | $ 88 | $ 1,304 | |
Wildfire-Related Class Action | ||||
Loss Contingencies [Line Items] | ||||
Loss contingency liability | 300 | |||
Net Income (Loss) | 145 | |||
Insurance Coverage Claims | ||||
Loss Contingencies [Line Items] | ||||
Insurance receivable | $ 272 | |||
Breach of Fiduciary Duties | ||||
Loss Contingencies [Line Items] | ||||
Settlement amount proposed | $ 117 |
WILDFIRE-RELATED CONTINGENCI_10
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties $ in Millions | Jul. 26, 2022 USD ($) | Feb. 24, 2021 claim | Nov. 20, 2017 lawsuit |
Loss Contingencies [Line Items] | |||
Number of causes of action (causes) | claim | 2 | ||
Settlement amount proposed | $ | $ 117 | ||
Derivative Lawsuits Filed in the San Francisco County Superior Court | |||
Loss Contingencies [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit | 2 |
WILDFIRE-RELATED CONTINGENCI_11
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation and Debt Claims) (Details) - Wildfire-Related Class Action $ in Millions | Dec. 31, 2022 USD ($) | Feb. 22, 2019 notice | Jun. 30, 2018 lawsuit |
Loss Contingencies [Line Items] | |||
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit | 2 | ||
Number of public offerings of notes with complaints against underwriters (offering) | notice | 4 | ||
Loss contingency liability | $ | $ 300 | ||
Percentage of common stock owned, Fire Victim Trust if common issues additional shares | 22.19% |
WILDFIRE-RELATED CONTINGENCI_12
WILDFIRE-RELATED CONTINGENCIES (Indemnification Obligations and D&O Insurance Coverage (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Insurance Coverage Claims | |
Loss Contingencies [Line Items] | |
Insurance receivable | $ 272 |
WILDFIRE-RELATED CONTINGENCI_13
WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co (Utility) - Complaints Brought By Butte County District Attorney - Loss from Wildfires | Mar. 17, 2020 count |
Loss Contingencies [Line Items] | |
Number of guilty involuntary manslaughter pleas | 84 |
Number of count related to unlawfully causing a fire (count) | 1 |
OTHER CONTINGENCIES AND COMMI_3
OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details) - USD ($) $ in Millions | 61 Months Ended | |||
Mar. 17, 2022 | Sep. 21, 2018 | Mar. 31, 2022 | Dec. 31, 2022 | |
Transmission Owner Rate Case Revenue | ||||
Loss Contingencies [Line Items] | ||||
Regulatory liabilities | $ 416 | |||
Regulatory assets | $ 258 | |||
Pacific Gas & Electric Co (Utility) | ||||
Loss Contingencies [Line Items] | ||||
Increase in regulatory liabilities | $ 62.5 | |||
Pacific Gas & Electric Co (Utility) | Electric | ||||
Loss Contingencies [Line Items] | ||||
Requested revenue rate | 98.85% | |||
Requested return on equity rate | 9.26% | |||
Requested return on equity rate, incentive component | 0.50% | |||
Actual return on equity rate | 9.76% |
OTHER CONTINGENCIES AND COMMI_4
OTHER CONTINGENCIES AND COMMITMENTS - 2022 Cost of Capital Application (Details) | Dec. 31, 2022 | Sep. 30, 2021 |
Commitments and Contingencies Disclosure [Abstract] | ||
Annual cost of capital adjustment, indicator | 4.50% | |
Annual cost of capital adjustment, basis point maximum | 100 | |
Proposed cost of long-term debt | 4.14% | |
Proposed return on preferred stock | 5.52% | |
Proposed return on equity | 11% | |
Annual cost of capital adjustment, indicator, basis point | 117 |
OTHER CONTINGENCIES AND COMMI_5
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Commitments and Contingencies Disclosure [Abstract] | ||
Accrued legal liabilities | $ 69 | $ 77 |
OTHER CONTINGENCIES AND COMMI_6
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 COMMI_7
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract] | ||
Topock natural gas compressor station | $ 284 | $ 299 |
Hinkley natural gas compressor station | 110 | 123 |
Former manufactured gas plant sites owned by the Utility or third parties | 750 | 667 |
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites | 112 | 104 |
Fossil fuel-fired generation facilities and sites | 26 | 70 |
Total environmental remediation liability | $ 1,282 | $ 1,263 |
OTHER CONTINGENCIES AND COMMI_8
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 1,050 |
Topock Site | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 240 |
Topock Site | Pacific Gas & Electric Co (Utility) | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90% |
Hinkley Natural Gas Compressor Station | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 126 |
Former Manufactured Gas Plant | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 511 |
Former Manufactured Gas Plant | Pacific Gas & Electric Co (Utility) | |
Long-term Purchase Commitment [Line Items] | |
Remediation cost recovery percentage | 90% |
Utility Owned Generation Facilities and Third Party Disposal Sites | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 51 |
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% |
Fossil Fuel Fired Generation | |
Long-term Purchase Commitment [Line Items] | |
Utility undiscounted future costs | $ 50 |
OTHER CONTINGENCIES AND COMMI_9
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Purchase Commitments) (Details) | 12 Months Ended |
Dec. 31, 2022 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 | $ 450,000,000 |
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance | |
Long-term Purchase Commitment [Line Items] | |
Insurance coverage, loss | 400,000,000 |
Humboldt Bay Unit | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage coverage provided by NEIL | 50,000,000 |
Amount of liability insurance for Humboldt Bay Unit 3 | 53,000,000 |
Diablo Canyon | |
Long-term Purchase Commitment [Line Items] | |
Maximum public liability per nuclear incident under Price-Anderson Act | 13,700,000,000 |
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act | 450,000,000 |
Maximum annual payment incurred per event under the loss sharing program | 275,000,000 |
Maximum annual payment incurred per event under the loss sharing program | $ 41,000,000 |
Period for inflation adjustment | 5 years |
Nuclear Incident | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | $ 3,200,000,000 |
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 | 500,000,000 |
Non-Nuclear Incident | |
Long-term Purchase Commitment [Line Items] | |
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon | 2,500,000,000 |
European Mutual Association for Nuclear Insurance | |
Long-term Purchase Commitment [Line Items] | |
Full insurance policy limit | 200,000,000 |
Potential premium obligation | 4,000,000 |
Nuclear Electric Insurance Limited | |
Long-term Purchase Commitment [Line Items] | |
Potential premium obligation | $ 41,000,000 |
OTHER CONTINGENCIES AND COMM_10
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Long-term Purchase Commitment [Line Items] | |
2023 | $ 4,416 |
2024 | 2,697 |
2025 | 2,956 |
2026 | 2,793 |
2027 | 2,558 |
Thereafter | 19,385 |
Total purchase commitments | 34,805 |
Renewable Energy | |
Long-term Purchase Commitment [Line Items] | |
2023 | 2,081 |
2024 | 2,052 |
2025 | 2,040 |
2026 | 1,980 |
2027 | 1,919 |
Thereafter | 17,807 |
Total purchase commitments | 27,879 |
Conventional Energy | |
Long-term Purchase Commitment [Line Items] | |
2023 | 482 |
2024 | 378 |
2025 | 715 |
2026 | 663 |
2027 | 579 |
Thereafter | 1,565 |
Total purchase commitments | 4,382 |
Other | |
Long-term Purchase Commitment [Line Items] | |
2023 | 60 |
2024 | 61 |
2025 | 61 |
2026 | 21 |
2027 | 7 |
Thereafter | 13 |
Total purchase commitments | 223 |
Natural Gas | |
Long-term Purchase Commitment [Line Items] | |
2023 | 1,746 |
2024 | 195 |
2025 | 140 |
2026 | 129 |
2027 | 53 |
Thereafter | 0 |
Total purchase commitments | 2,263 |
Nuclear Fuel | |
Long-term Purchase Commitment [Line Items] | |
2023 | 47 |
2024 | 11 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
Thereafter | 0 |
Total purchase commitments | $ 58 |
OTHER CONTINGENCIES AND COMM_11
OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Power Purchases and Electric Capacity | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Costs incurred for power purchases and electric capacity | $ 2,800 | $ 3,000 | $ 2,900 |
Nuclear Fuel | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Payments for nuclear fuel | 44 | 79 | 111 |
Gas Contracts | |||
Third-Party Power Purchase Agreements [Line Items] | |||
Cost of goods | $ 2,400 | $ 1,200 | $ 800 |
OTHER CONTINGENCIES AND COMM_12
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details) $ in Millions | Dec. 31, 2022 USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2023 | $ 88 |
2024 | 85 |
2025 | 83 |
2026 | 81 |
2027 | 80 |
Thereafter | 3,518 |
Total minimum lease payments | $ 3,935 |
OTHER CONTINGENCIES AND COMM_13
OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Leased Assets [Line Items] | |||
Payments for other commitments | $ 63 | $ 50 | $ 45 |
SB 901 Securitization | Secured Debt | |||
Operating Leased Assets [Line Items] | |||
Initial shareholder contribution, contributed in 2024 | $ 1,000 | ||
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 |
SCHEDULE I _ CONDENSED FINANC_2
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating expenses | $ (19,843) | $ (18,759) | $ (16,714) |
Interest income | 162 | 20 | 39 |
Interest expense | (1,917) | (1,601) | (1,260) |
Other income, net | 394 | 457 | 483 |
Reorganization items, net | 0 | (11) | (1,959) |
Income tax provision (benefit) | (1,338) | 836 | 362 |
Income (Loss) Attributable to Common Shareholders | 1,800 | (102) | (1,318) |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates) | 21 | 7 | (17) |
Total other comprehensive income (loss) | $ 15 | $ 7 | $ (17) |
Weighted Average Common Shares Outstanding, Basic (in shares) | 1,987,000,000 | 1,985,000,000 | 1,257,000,000 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 2,132,000,000 | 1,985,000,000 | 1,257,000,000 |
Net earnings (loss) per common share, basic (in dollars per share) | $ 0.91 | $ (0.05) | $ (1.05) |
Net earnings (loss) per common share, diluted (in dollars per share) | $ 0.84 | $ (0.05) | $ (1.05) |
Pension and other postretirement benefit plans obligations, tax | $ 8 | $ 3 | $ 7 |
Treasury stock, shares at cost (in shares) | 247,743,590 | 477,743,590 | |
PG&E Corporation | |||
Operating expenses | $ (193) | $ (124) | (103) |
Interest income | 3 | 0 | 0 |
Interest expense | (261) | (230) | (149) |
Other income, net | (201) | (54) | 13 |
Reorganization items, net | 0 | 1 | (1,649) |
Equity in earnings of subsidiaries | 2,154 | 137 | 411 |
Income (loss) before income taxes | 1,611 | (152) | (1,350) |
Income tax provision (benefit) | (132) | (64) | (46) |
Income (Loss) Attributable to Common Shareholders | 1,743 | (88) | (1,304) |
Other Comprehensive Income | |||
Pension and other postretirement benefit plans obligations (net of taxes of $8, $3, and $7, at respective dates) | 21 | 7 | (17) |
Total other comprehensive income (loss) | 21 | 7 | (17) |
Comprehensive Income (Loss) | $ 1,764 | $ (81) | $ (1,321) |
Weighted Average Common Shares Outstanding, Basic (in shares) | 2,235,000,000 | 2,463,000,000 | 1,257,000,000 |
Weighted Average Common Shares Outstanding, Diluted (in shares) | 2,380,000,000 | 2,463,000,000 | 1,257,000,000 |
Net earnings (loss) per common share, basic (in dollars per share) | $ 0.78 | $ (0.05) | $ (1.05) |
Net earnings (loss) per common share, diluted (in dollars per share) | $ 0.73 | $ (0.05) | $ (1.05) |
Pension and other postretirement benefit plans obligations, tax | $ 8 | $ 3 | $ 7 |
PG&E Corporation | Administrative service revenue | |||
Administrative service revenue | $ 109 | $ 118 | $ 127 |
SCHEDULE I _ CONDENSED FINANC_3
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Current Assets | |||
Cash and cash equivalents | $ 734 | $ 291 | $ 484 |
Other | 1,433 | 882 | |
Total current assets | 12,815 | 11,077 | |
Noncurrent Assets | |||
Equipment | 107,154 | 98,960 | |
Accumulated depreciation | (30,946) | (29,134) | |
Net property, plant, and equipment | 76,208 | 69,826 | |
TOTAL ASSETS | 118,644 | 103,327 | |
Current Liabilities | |||
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 2,268 | 4,481 | |
Other current liabilities | 3,372 | 2,436 | |
Total current liabilities | 15,788 | 17,427 | |
Noncurrent Liabilities | |||
Long-term debt | 47,742 | 38,225 | |
Other | 4,291 | 4,308 | |
Total noncurrent liabilities | 79,781 | 64,677 | |
Common Shareholders’ Equity | |||
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates | 32,887 | 35,129 | |
Reinvested earnings | (7,542) | (9,284) | |
Accumulated other comprehensive income (loss) | (5) | (20) | |
Total shareholders’ equity | 22,823 | 20,971 | |
TOTAL LIABILITIES AND EQUITY | 118,644 | 103,327 | |
PG&E Corporation | |||
Current Assets | |||
Cash and cash equivalents | 125 | 126 | |
Advances to affiliates | 46 | 21 | |
Income taxes receivable | 10 | 10 | |
Other | 12 | 12 | |
Total current assets | 193 | 169 | |
Noncurrent Assets | |||
Equipment | 0 | 2 | |
Accumulated depreciation | 0 | (2) | |
Net property, plant, and equipment | 0 | 0 | |
Investments in subsidiaries | 33,021 | 30,232 | |
Other investments | 160 | 181 | |
Deferred income taxes | 423 | 297 | |
Total noncurrent assets | 33,604 | 30,710 | |
TOTAL ASSETS | 33,797 | 30,879 | |
Current Liabilities | |||
Long-term debt, classified as current (includes $168 million and $18 million related to VIEs at respective dates) | 27 | 27 | |
Accounts payable – other | 88 | 200 | |
Other current liabilities | 369 | 69 | |
Total current liabilities | 484 | 296 | |
Noncurrent Liabilities | |||
Long-term debt | 4,588 | 4,592 | |
Other | 134 | 168 | |
Total noncurrent liabilities | 4,722 | 4,760 | |
Common Shareholders’ Equity | |||
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 1,987,784,948 and 1,985,400,540 shares outstanding at respective dates | 36,132 | 35,129 | |
Reinvested earnings | (7,542) | (9,286) | |
Accumulated other comprehensive income (loss) | 1 | (20) | |
Total shareholders’ equity | 28,591 | 25,823 | |
TOTAL LIABILITIES AND EQUITY | $ 33,797 | $ 30,879 |
SCHEDULE I _ CONDENSED FINANC_4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Aug. 11, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | ||
Cash Flows from Operating Activities | |||||
Net Income (Loss) | $ 1,814 | $ (88) | $ (1,304) | ||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||
Deferred income taxes and tax credits, net | (452) | 1,783 | 1,097 | ||
Reorganization items, net | 0 | (73) | 1,458 | ||
Liabilities subject to compromise | 0 | 0 | 413 | ||
Net cash provided by operating activities | 3,721 | 2,262 | (19,130) | ||
Cash Flows from Investing Activities | |||||
Net cash used in investing activities | (10,214) | (6,905) | (7,748) | ||
Cash Flows From Financing Activities: | |||||
Bridge facility financing fees | 0 | 0 | (73) | ||
Repayment of long-term debt | (5,968) | (87) | (764) | ||
Intercompany note to PG&E Corporation | $ (145) | ||||
Equity Units issued | 0 | 0 | 1,304 | ||
Other | 53 | (29) | (40) | ||
Net cash provided by financing activities | 7,133 | 4,323 | 25,928 | ||
Net change in cash, cash equivalents, and restricted cash | 640 | (320) | (950) | ||
Cash, cash equivalents, and restricted cash at January 1 | 307 | 627 | 1,577 | ||
Cash, cash equivalents, and restricted cash at December 31 | 947 | 307 | 627 | ||
Cash received (paid) for: | |||||
Interest, net of amounts capitalized | (1,607) | (1,404) | (1,563) | ||
Income taxes, net | 0 | (99) | 0 | ||
Noncash Investing and Financing Items [Abstract] | |||||
Common stock issued in satisfaction of liabilities | 0 | 0 | 8,276 | ||
Adjustments to Treasury Stock Acquired, Noncash | 2,337 | (4,854) | 0 | ||
PG&E Corporation | |||||
Cash Flows from Operating Activities | |||||
Net Income (Loss) | 1,743 | (88) | (1,304) | ||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||
Stock-based compensation amortization | 95 | 51 | 28 | ||
Equity in earnings of subsidiaries | (2,160) | (139) | (412) | ||
Deferred income taxes and tax credits, net | (126) | (60) | (50) | ||
Reorganization items, net | 0 | (32) | 1,548 | ||
Current income taxes receivable/payable | 0 | 2 | 0 | ||
Liabilities subject to compromise | 0 | 0 | 12 | ||
Other | 339 | 81 | 97 | ||
Net cash provided by operating activities | (109) | (185) | (81) | ||
Cash Flows from Investing Activities | |||||
Investment in subsidiaries | (994) | 0 | (12,986) | ||
Dividends received from subsidiaries | [1] | 1,275 | 0 | 0 | |
Net cash used in investing activities | 281 | 0 | (12,986) | ||
Cash Flows From Financing Activities: | |||||
Bridge facility financing fees | 0 | 0 | (40) | ||
Proceeds from issuance of long-term debt | 0 | 0 | 4,660 | ||
Repayment of long-term debt | (28) | (28) | (664) | ||
Intercompany note to PG&E Corporation | (145) | 145 | 0 | ||
Common stock issued | 0 | 0 | 7,582 | ||
Equity Units issued | 0 | 0 | 1,304 | ||
Other | 0 | (29) | 0 | ||
Net cash provided by financing activities | (173) | 88 | 12,842 | ||
Net change in cash, cash equivalents, and restricted cash | (1) | (97) | (225) | ||
Cash, cash equivalents, and restricted cash at January 1 | 126 | 223 | 448 | ||
Cash, cash equivalents, and restricted cash at December 31 | 125 | 126 | 223 | ||
Cash received (paid) for: | |||||
Interest, net of amounts capitalized | (233) | (207) | (105) | ||
Income taxes, net | 0 | 1 | 0 | ||
Noncash Investing and Financing Items [Abstract] | |||||
Common stock issued in satisfaction of liabilities | 0 | 0 | 8,276 | ||
Adjustments to Treasury Stock Acquired, Noncash | $ (2,337) | $ 4,854 | $ 0 | ||
[1]Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On June 15, 2022, the Board of Directors of the Utility reinstated the dividend on the Utility’s common stock. |
SCHEDULE II _ CONSOLIDATED VA_2
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Balance at Beginning of Period | $ 171 | $ 146 | $ 43 |
Charged to Costs and Expenses | 146 | 136 | 138 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 151 | 111 | 35 |
Balance at End of Period | $ 166 | $ 171 | $ 146 |