PG&E CORP, 10-K filed on 2/25/2021
Annual Report
v3.20.4
Cover Page - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Feb. 22, 2021
Jun. 30, 2020
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2020    
Current Fiscal Year End Date --12-31    
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 77 Beale Street    
Entity Address, Address Line Two P.O. Box 770000    
Entity Address, City or Town San Francisco,    
Entity Address, State or Province CA    
Entity Address, Postal Zip Code 94117    
City Area Code 415    
Local Phone Number 973-1000    
Entity Well-known Seasoned Issuer No    
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     $ 12,130
Entity Common Stock, Shares Outstanding   1,984,683,820  
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 2021 Annual Meetings of ShareholdersPart III (Items 10, 11, 12, 13 and 14)
    
Amendment Flag false    
Document Fiscal Year Focus 2020    
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 77 Beale Street    
Entity Address, Address Line Two P.O. Box 770000    
Entity Address, City or Town San Francisco,    
Entity Address, State or Province CA    
Entity Address, Postal Zip Code 94117    
City Area Code 415    
Local Phone Number 973-1000    
Entity Well-known Seasoned Issuer No    
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   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 2021 Annual Meetings of ShareholdersPart 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 $25 per share, 5% nonredeemable    
Trading Symbol PCG-PC    
Security Exchange Name NYSEAMER    
v3.20.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Operating Revenues      
Total operating revenues $ 18,469 $ 17,129 $ 16,759
Operating Expenses      
Operating and maintenance 8,684 8,725 7,153
Wildfire-related claims, net of insurance recoveries 251 11,435 11,771
Wildfire fund expense 413 0 0
Depreciation, amortization, and decommissioning 3,468 3,234 3,036
Total operating expenses 16,714 27,223 26,459
Operating Income (Loss) 1,755 (10,094) (9,700)
Interest income 39 82 76
Interest expense (1,260) (934) (929)
Other income, net 483 250 424
Reorganization items, net (1,959) (346) 0
Loss Before Income Taxes (942) (11,042) (10,129)
Income tax provision (benefit) 362 (3,400) (3,292)
Net Loss (1,304) (7,642) (6,837)
Preferred stock dividend requirement of subsidiary 14 14 14
Loss Attributable to Common Shareholders $ (1,318) $ (7,656) $ (6,851)
Weighted Average Common Shares Outstanding, Basic (in shares) 1,257 528 517
Weighted Average Common Shares Outstanding, Diluted (in shares) 1,257 528 517
Net Loss Per Common Share, Basic (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Net Loss Per Common Share, Diluted (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Pacific Gas & Electric Co (Utility)      
Operating Revenues      
Total operating revenues $ 18,469 $ 17,129 $ 16,760
Operating Expenses      
Operating and maintenance 8,707 8,750 7,153
Wildfire-related claims, net of insurance recoveries 251 11,435 11,771
Wildfire fund expense 413 0 0
Depreciation, amortization, and decommissioning 3,469 3,233 3,036
Total operating expenses 16,738 27,247 26,459
Operating Income (Loss) 1,731 (10,118) (9,699)
Interest income 39 82 74
Interest expense (1,111) (912) (914)
Other income, net 470 239 426
Reorganization items, net (310) (320) 0
Loss Before Income Taxes 819 (11,029) (10,113)
Income tax provision (benefit) 408 (3,407) (3,295)
Net Loss 411 (7,622) (6,818)
Preferred stock dividend requirement 14 14 14
Loss Attributable to Common Shareholders 397 (7,636) (6,832)
Electric      
Operating Revenues      
Total operating revenues 13,858 12,740 12,713
Operating Expenses      
Cost of goods 3,116 3,095 3,828
Electric | Pacific Gas & Electric Co (Utility)      
Operating Revenues      
Total operating revenues 13,858 12,740 12,713
Operating Expenses      
Cost of goods 3,116 3,095 3,828
Natural gas      
Operating Revenues      
Total operating revenues 4,611 4,389 4,046
Operating Expenses      
Cost of goods 782 734 671
Natural gas | Pacific Gas & Electric Co (Utility)      
Operating Revenues      
Total operating revenues 4,611 4,389 4,047
Operating Expenses      
Cost of goods $ 782 $ 734 $ 671
v3.20.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Net Loss $ (1,304) $ (7,642) $ (6,837)
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (17) (1) 4
Total other comprehensive income (loss) (17) (1) 4
Comprehensive Loss (1,321) (7,643) (6,833)
Preferred stock dividend requirement of subsidiary 14 14 14
Comprehensive Loss Attributable to Common Shareholders (1,335) (7,657) (6,847)
Pacific Gas & Electric Co (Utility)      
Net Loss 411 (7,622) (6,818)
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (6) 2 (5)
Total other comprehensive income (loss) (6) 2 (5)
Comprehensive Loss $ 405 $ (7,620) $ (6,823)
v3.20.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pension and other postretirement benefit plans obligations, tax $ 7 $ 0 $ 2
Pacific Gas & Electric Co (Utility)      
Pension and other postretirement benefit plans obligations, tax $ 2 $ 1 $ 2
v3.20.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Current Assets    
Cash and cash equivalents $ 484 $ 1,570
Restricted Cash 143 7
Accounts receivable    
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) 1,883 1,287
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) 1,083 969
Regulatory balancing accounts 2,001 2,114
Other 1,172 2,617
Regulatory assets 410 315
Inventories    
Gas stored underground and fuel oil 95 97
Materials and supplies 533 550
Wildfire fund asset 464 0
Other 1,334 639
Total current assets 9,602 10,165
Property, Plant, and Equipment    
Electric 66,982 62,707
Gas 24,135 22,688
Construction work in progress 2,757 2,675
Other 20 20
Total property, plant, and equipment 93,894 88,090
Accumulated depreciation (27,758) (26,455)
Net property, plant, and equipment 66,136 61,635
Other Noncurrent Assets    
Regulatory assets 8,978 6,066
Nuclear decommissioning trusts 3,538 3,173
Operating lease right of use asset 1,741 2,286
Wildfire fund asset 5,816 0
Income taxes receivable 67 67
Other 1,978 1,804
Total other noncurrent assets 22,118 13,396
TOTAL ASSETS 97,856 85,196
Current Liabilities    
Short-term borrowings 3,547 0
Long-term debt, classified as current 28 0
Debtor-in-possession financing, classified as current 0 1,500
Accounts payable    
Trade creditors 2,402 1,954
Regulatory balancing accounts 1,245 1,797
Other 580 566
Operating lease liabilities 533 556
Disputed claims and customer refunds 242 0
Interest payable 498 4
Wildfire-related claims 2,250 0
Other 2,256 1,254
Total current liabilities 13,581 7,631
Noncurrent Liabilities    
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) 37,288 0
Regulatory liabilities 10,424 9,270
Pension and other postretirement benefits 2,444 1,884
Asset retirement obligations 6,412 5,854
Deferred income taxes 1,398 320
Operating lease liabilities 1,208 1,730
Other 3,848 2,573
Total noncurrent liabilities 63,022 21,631
Liabilities Subject to Compromise 0 50,546
Contingencies and Commitments
Shareholders' Equity    
Common stock, no par value 30,224 13,038
Reinvested earnings (9,196) (7,892)
Accumulated other comprehensive income (27) (10)
Total shareholders' equity 21,001 5,136
Noncontrolling Interest - Preferred Stock of Subsidiary 252 252
Total equity 21,253 5,388
TOTAL LIABILITIES AND EQUITY 97,856 85,196
Pacific Gas & Electric Co (Utility)    
Current Assets    
Cash and cash equivalents 261 1,122
Restricted Cash 143 7
Accounts receivable    
Customers (net of allowance for doubtful accounts of $146 million and $43 million at respective dates) (includes $1.63 billion and $0 related to VIEs, net of allowance for doubtful accounts of $143 million and $0 at respective dates) 1,883 1,287
Accrued unbilled revenue (includes $959 million and $0 related to VIEs at respective dates) 1,083 969
Regulatory balancing accounts 2,001 2,114
Other 1,180 2,647
Regulatory assets 410 315
Inventories    
Gas stored underground and fuel oil 95 97
Materials and supplies 533 550
Wildfire fund asset 464 0
Other 1,321 628
Total current assets 9,374 9,736
Property, Plant, and Equipment    
Electric 66,982 62,707
Gas 24,135 22,688
Construction work in progress 2,757 2,675
Other 18 18
Total property, plant, and equipment 93,892 88,088
Accumulated depreciation (27,756) (26,453)
Net property, plant, and equipment 66,136 61,635
Other Noncurrent Assets    
Regulatory assets 8,978 6,066
Nuclear decommissioning trusts 3,538 3,173
Operating lease right of use asset 1,736 2,279
Wildfire fund asset 5,816 0
Income taxes receivable 66 66
Other 1,818 1,659
Total other noncurrent assets 21,952 13,243
TOTAL ASSETS 97,462 84,614
Current Liabilities    
Short-term borrowings 3,547 0
Debtor-in-possession financing, classified as current 0 1,500
Accounts payable    
Trade creditors 2,366 1,949
Regulatory balancing accounts 1,245 1,797
Other 624 675
Operating lease liabilities 530 553
Disputed claims and customer refunds 242 0
Interest payable 444 4
Wildfire-related claims 2,250 0
Other 2,248 1,263
Total current liabilities 13,496 7,741
Noncurrent Liabilities    
Long-term debt (includes $1.0 billion and $0 related to VIEs at respective dates) 32,664 0
Regulatory liabilities 10,424 9,270
Pension and other postretirement benefits 2,328 1,884
Asset retirement obligations 6,412 5,854
Deferred income taxes 1,570 442
Operating lease liabilities 1,206 1,726
Other 3,886 2,626
Total noncurrent liabilities 58,490 21,802
Liabilities Subject to Compromise 0 49,736
Contingencies and Commitments
Shareholders' Equity    
Preferred stock 258 258
Common stock, no par value 1,322 1,322
Additional paid-in capital 28,286 8,550
Reinvested earnings (4,385) (4,796)
Accumulated other comprehensive income (5) 1
Total shareholders' equity 25,476 5,335
TOTAL LIABILITIES AND EQUITY $ 97,462 $ 84,614
v3.20.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Allowance for doubtful accounts $ 146 $ 43
Customers, VIE 1,630 0
Allowance for doubtful accounts, customers, VIE 143 0
Accrued unbilled revenue 959 0
Short-term borrowings, VIE $ 1,000 $ 0
Common stock, par value (in dollars per share) $ 0 $ 0
Common stock, shares authorized (in shares) 3,600,000,000 800,000,000
Common stock, shares outstanding (in shares) 1,984,678,673 529,236,741
Pacific Gas & Electric Co (Utility)    
Allowance for doubtful accounts $ 146 $ 43
Customers, VIE 1,630 0
Allowance for doubtful accounts, customers, VIE 143 0
Accrued unbilled revenue 959 0
Short-term borrowings, VIE $ 1,000 $ 0
Common stock, par value (in dollars per share) $ 5 $ 5
Common stock, shares authorized (in shares) 800,000,000 800,000,000
Common stock, shares outstanding (in shares) 264,374,809 264,374,809
v3.20.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Cash Flows from Operating Activities      
Net income (Loss) $ (1,304) $ (7,642) $ (6,837)
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, amortization, and decommissioning 3,468 3,234 3,036
Allowance for equity funds used during construction (140) (79) (129)
Deferred income taxes and tax credits, net 1,097 (2,948) (2,532)
Reorganization items, net 1,458 108 0
Wildfire fund expense 413 0 0
Disallowed capital expenditures 17 581 (45)
Other 399 207 332
Effect of changes in operating assets and liabilities:      
Accounts receivable (1,182) (104) (121)
Wildfire-related insurance receivable 1,564 35 (1,698)
Inventories 6 (80) (73)
Accounts payable 58 516 409
Wildfire-related claims (16,525) (114) 13,665
Income taxes receivable/payable 0 23 (23)
Other current assets and liabilities (1,079) 77 (281)
Regulatory assets, liabilities, and balancing accounts, net (2,451) (1,417) (800)
Liabilities subject to compromise 413 12,222 0
Contributions to wildfire fund (5,200) 0 0
Other noncurrent assets and liabilities (142) 197 (151)
Net cash provided by (used in) operating activities (19,130) 4,816 4,752
Cash Flows from Investing Activities      
Capital expenditures (7,690) (6,313) (6,514)
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,518 956 1,412
Purchases of nuclear decommissioning trust investments (1,590) (1,032) (1,485)
Other 14 11 23
Net cash used in investing activities (7,748) (6,378) (6,564)
Cash Flows from Financing Activities      
Proceeds from debtor-in-possession credit facility 500 1,850 0
Repayments of debtor-in-possession credit facility (2,000) (350) 0
Debtor-in-possession credit facility debt issuance costs (6) (113) 0
Bridge facility financing fees (73) 0 0
Repayment of long-term debt (764) 0 (795)
Borrowings under credit facilities 8,554 0 3,960
Repayments under credit facilities (3,949) 0 (775)
Credit facilities financing fees (22) 0 0
Net repayments of commercial paper, net of discount 0 0 (182)
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates 1,448 0 600
Short-term debt matured 0 0 (750)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs 13,497 0 793
Exchanged debt financing fees (103) 0 0
Common stock issued 7,582 85 200
Equity Units issued 1,304 0 0
Other (40) (8) (20)
Net cash provided by financing activities 25,928 1,464 3,031
Net change in cash, cash equivalents, and restricted cash (950) (98) 1,219
Cash, cash equivalents, and restricted cash at January 1 1,577 1,675 456
Cash, cash equivalents, and restricted cash at December 31 627 1,577 1,675
Less: Restricted cash and restricted cash equivalents (143) (7) (7)
Cash and cash equivalents at December 31 484 1,570 1,668
Cash paid for:      
Interest, net of amounts capitalized (1,563) (10) (786)
Income taxes, net 0 0 (49)
Supplemental disclosures of noncash investing and financing activities      
Capital expenditures financed through accounts payable 515 826 368
Operating lease liabilities arising from obtaining ROU assets 13 2,816 0
Common stock issued in satisfaction of liabilities 8,276 0 0
Pacific Gas & Electric Co (Utility)      
Cash Flows from Operating Activities      
Net income (Loss) 411 (7,622) (6,818)
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, amortization, and decommissioning 3,469 3,233 3,036
Allowance for equity funds used during construction (140) (79) (129)
Deferred income taxes and tax credits, net 1,141 (2,952) (2,548)
Reorganization items, net (90) 97 0
Wildfire fund expense 413 0 0
Disallowed capital expenditures 17 581 (45)
Other 370 167 258
Effect of changes in operating assets and liabilities:      
Accounts receivable (1,160) (132) (122)
Wildfire-related insurance receivable 1,564 35 (1,698)
Inventories 6 (80) (73)
Accounts payable (24) 579 421
Wildfire-related claims (16,525) (114) 13,665
Income taxes receivable/payable 0 5 (5)
Other current assets and liabilities (1,141) 101 (301)
Regulatory assets, liabilities, and balancing accounts, net (2,451) (1,417) (800)
Liabilities subject to compromise 401 12,194 0
Contributions to wildfire fund (5,200) 0 0
Other noncurrent assets and liabilities (108) 214 (137)
Net cash provided by (used in) operating activities (19,047) 4,810 4,704
Cash Flows from Investing Activities      
Capital expenditures (7,690) (6,313) (6,514)
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,518 956 1,412
Purchases of nuclear decommissioning trust investments (1,590) (1,032) (1,485)
Other 14 11 23
Net cash used in investing activities (7,748) (6,378) (6,564)
Cash Flows from Financing Activities      
Proceeds from debtor-in-possession credit facility 500 1,850 0
Repayments of debtor-in-possession credit facility (2,000) (350) 0
Debtor-in-possession credit facility debt issuance costs (6) (97) 0
Bridge facility financing fees (33) 0 0
Repayment of long-term debt (100)   (445)
Borrowings under credit facilities 8,554 0 3,535
Repayments under credit facilities (3,949) 0 (650)
Credit facilities financing fees (22) 0 0
Net repayments of commercial paper, net of discount 0 0 (50)
Short-term debt financing, net of issuance costs of $2, $0, and $0 at respective dates 1,448 0 250
Short-term debt matured 0 0 (750)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs 8,837 0 793
Exchanged debt financing fees (103) 0 0
Equity contribution from PG&E Corporation 12,986 0 45
Other (42) (8) (20)
Net cash provided by financing activities 26,070 1,395 2,708
Net change in cash, cash equivalents, and restricted cash (725) (173) 848
Cash, cash equivalents, and restricted cash at January 1 1,129 1,302 454
Cash, cash equivalents, and restricted cash at December 31 404 1,129 1,302
Less: Restricted cash and restricted cash equivalents (143) (7) (7)
Cash and cash equivalents at December 31 261 1,122 1,295
Cash paid for:      
Interest, net of amounts capitalized (1,458) (7) (773)
Income taxes, net 0 0 (59)
Supplemental disclosures of noncash investing and financing activities      
Capital expenditures financed through accounts payable 515 826 368
Operating lease liabilities arising from obtaining ROU assets 13 2,807 0
Common stock equity infusion from PG&E Corporation used to satisfy liabilities $ 6,750 $ 0 $ 0
v3.20.4
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Cash Flows from Financing Activities      
Discount on net issuances of commercial paper $ 0 $ 0 $ 1
Issuance costs for short-term debt 2 0 0
Premium, discount, and issuance costs on proceeds from long-term debt 178 0 7
Pacific Gas & Electric Co (Utility)      
Cash Flows from Financing Activities      
Discount on net issuances of commercial paper 0 0 0
Issuance costs for short-term debt 2 0 0
Premium, discount, and issuance costs on proceeds from long-term debt $ 88 $ 0 $ 7
v3.20.4
CONSOLIDATED STATEMENTS OF EQUITY - USD ($)
Total
Pacific Gas & Electric Co (Utility)
Preferred Stock
Pacific Gas & Electric Co (Utility)
Common Stock
Common Stock
Pacific Gas & Electric Co (Utility)
Additional Paid-in Capital
Pacific Gas & Electric Co (Utility)
Reinvested Earnings
Reinvested Earnings
Pacific Gas & Electric Co (Utility)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Loss
Pacific Gas & Electric Co (Utility)
Total Shareholders' Equity
Total Shareholders' Equity
Pacific Gas & Electric Co (Utility)
Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance (in shares) at Dec. 31, 2017       514,755,845                  
Beginning balance at Dec. 31, 2017 $ 19,472,000,000   $ 258,000,000 $ 12,632,000,000 $ 1,322,000,000 $ 8,505,000,000 $ 6,596,000,000 $ 9,656,000,000 $ (8,000,000) $ 6,000,000 $ 19,220,000,000 $ 19,747,000,000 $ 252,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (Loss) (6,837,000,000) $ (6,818,000,000)         (6,837,000,000) (6,818,000,000)     (6,837,000,000) (6,818,000,000)  
Other comprehensive income (loss) 4,000,000 (5,000,000)         5,000,000 2,000,000 (1,000,000) (7,000,000) 4,000,000 (5,000,000)  
Equity contribution           45,000,000           45,000,000  
Common stock issued, net (in shares)       5,582,865                  
Common stock issued, net 200,000,000     $ 200,000,000             200,000,000    
Stock-based compensation amortization 78,000,000     $ 78,000,000             78,000,000    
Preferred stock dividend requirement of subsidiary (14,000,000)           (14,000,000)       (14,000,000)    
Preferred stock dividend   0           (14,000,000)       (14,000,000)  
Ending balance (in shares) at Dec. 31, 2018       520,338,710                  
Ending balance at Dec. 31, 2018 12,903,000,000   258,000,000 $ 12,910,000,000 1,322,000,000 8,550,000,000 (250,000,000) 2,826,000,000 (9,000,000) (1,000,000) 12,651,000,000 12,955,000,000 252,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (Loss) (7,642,000,000) (7,622,000,000)         (7,642,000,000) (7,622,000,000)     (7,642,000,000) (7,622,000,000)  
Other comprehensive income (loss) (1,000,000) 2,000,000             (1,000,000) 2,000,000 (1,000,000) 2,000,000  
Common stock issued, net (in shares)       8,898,031                  
Common stock issued, net 85,000,000     $ 85,000,000             85,000,000    
Stock-based compensation amortization $ 43,000,000     $ 43,000,000             43,000,000    
Preferred stock dividend   $ 0                      
Ending balance (in shares) at Dec. 31, 2019 529,236,741 264,374,809   529,236,741                  
Ending balance at Dec. 31, 2019 $ 5,388,000,000   258,000,000 $ 13,038,000,000 1,322,000,000 8,550,000,000 (7,892,000,000) (4,796,000,000) (10,000,000) 1,000,000 5,136,000,000 5,335,000,000 252,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income (Loss) (1,304,000,000) $ 411,000,000         (1,304,000,000) 411,000,000     (1,304,000,000) 411,000,000  
Other comprehensive income (loss) (17,000,000) (6,000,000)             (17,000,000) (6,000,000) (17,000,000) (6,000,000)  
Equity contribution           19,736,000,000           19,736,000,000  
Common stock issued, net (in shares)       1,455,441,932                  
Common stock issued, net 15,854,000,000     $ 15,854,000,000             15,854,000,000    
Equity units issued 1,304,000,000     1,304,000,000             1,304,000,000    
Stock-based compensation amortization $ 28,000,000     $ 28,000,000             28,000,000    
Preferred stock dividend   $ 0                      
Ending balance (in shares) at Dec. 31, 2020 1,984,678,673 264,374,809   1,984,678,673                  
Ending balance at Dec. 31, 2020 $ 21,253,000,000   $ 258,000,000 $ 30,224,000,000 $ 1,322,000,000 $ 28,286,000,000 $ (9,196,000,000) $ (4,385,000,000) $ (27,000,000) $ (5,000,000) $ 21,001,000,000 $ 25,476,000,000 $ 252,000,000
v3.20.4
ORGANIZATION AND BASIS OF PRESENTATION
 12 Months Ended
Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
ORGANIZATION AND BASIS OF PRESENTATION ORGANIZATION AND BASIS OF PRESENTATION
Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

Chapter 11 Filing and Going Concern

The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection on January 29, 2019. Uncertainty regarding these matters previously raised substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns.

As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on the Effective Date of July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date the financial statements were issued. (For more information regarding the Chapter 11 Cases, see Note 2 below.)
v3.20.4
BANKRUPTCY FILING
 12 Months Ended
Dec. 31, 2020
Reorganizations [Abstract]  
BANKRUPTCY FILING BANKRUPTCY FILING
Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.
Significant Bankruptcy Court Actions

Plan of Reorganization and Restructuring Support Agreements

On June 19, 2020, PG&E Corporation and the Utility and the Shareholder Proponents filed the Plan. On June 20, 2020, the Bankruptcy Court confirmed the Plan by issuing the Confirmation Order. PG&E Corporation and the Utility emerged from Chapter 11 on the Effective Date of July 1, 2020.

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA with certain holders of wildfire insurance subrogation claims (such claims, the “Subrogation Claims”). On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. As of December 31, 2020, PG&E Corporation and the Utility incurred $53 million in professional fees related to the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 14 for further information on the Subrogation RSA.

On December 6, 2019, PG&E Corporation and the Utility entered the TCC RSA, which was subsequently amended on December 16, 2019, with the TCC, the attorneys and other advisors and agents for holders of claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and Public Entity Wildfire Claims (as defined below)) (the “Fire Victim Claims”) that are signatories to the TCC RSA, and the Shareholder Proponents. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 14 for further information on the TCC RSA.

On January 22, 2020, PG&E Corporation and the Utility entered into the Noteholder RSA with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” therein and the Shareholder Proponents. On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA.

Confirmation of the Plan of Reorganization

The Plan as confirmed by the Confirmation Order provides for certain transactions and the satisfaction and treatment of claims against and interests in PG&E Corporation and the Utility, each in accordance with the terms of the Plan, including the transactions described below. The Plan provides for the following treatment of various classes of claims as described below. PG&E Corporation and the Utility are in the process of resolving and paying claims pursuant to the treatment provided under the Plan.

•PG&E Corporation and the Utility funded the Fire Victim Trust for the benefit of all holders of Fire Victim Claims, whose claims were channeled to the Fire Victim Trust on the Effective Date with no recourse to PG&E Corporation and the Utility. In full and final satisfaction, release, and discharge of all Fire Victim Claims, the Fire Victim Trust was funded with $5.4 billion in cash (with an additional $1.35 billion in cash to be funded on a deferred basis), common stock of PG&E Corporation representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments), plus the assignment of certain rights and causes of action. As a result of such funding, all Fire Victim Claims have been satisfied, released, discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility;

•PG&E Corporation and the Utility funded a trust (the “Subrogation Wildfire Trust”) for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. As a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility;

•PG&E Corporation and the Utility paid $1.0 billion in cash to certain local public entities (the “Settling Public Entities”) that entered into PSAs with PG&E Corporation and the Utility and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities in full and final satisfaction, release and discharge of such Settling Public Entities’ wildfire related claims;
•The following pre-petition notes of the Utility: (a) 3.50% Senior Notes due October 1, 2020; (b) 4.25% Senior Notes due May 15, 2021; (c) 3.25% Senior Notes due September 15, 2021; and (d) 2.45% Senior Notes due August 15, 2022), (collectively, the “Utility Short-Term Senior Notes”); the following pre-petition notes of the Utility: (a) 6.05% Senior Notes due March 1, 2034; (b) 5.80% Senior Notes due March 1, 2037; (c) 6.35% Senior Notes due February 15, 2038; (d) 6.25% Senior Notes due March 1, 2039; (e) 5.40% Senior Notes due January 15, 2040; and (f) 5.125% Senior Notes due November 15, 2043, (collectively, the “Utility Long-Term Senior Notes) and the pre-petition credit agreements of the Utility, including in connection with the pollution control bonds (except for $100 million of pollution control bonds (Series 2008F and 2010E), which were repaid in cash) (collectively, the “Utility Funded Debt”) were refinanced and all other Utility pre-petition senior notes (collectively, the “Utility Reinstated Senior Notes”) were reinstated and collateralized on or around the Effective Date through the issuance of a corresponding series of first mortgage bonds of the Utility;

•PG&E Corporation paid in full all of its pre-petition funded debt obligations that were allowed in the Chapter 11 Cases;

•PG&E Corporation and the Utility repaid all borrowings under the DIP Facilities and have paid all other allowed administrative expense claims in accordance with the Plan;

•Holders of allowed claims by a governmental authority entitled to priority in payment under sections 502(i) and 507(a)(8) of the Bankruptcy Code (“Priority Tax Claims”) have received or will receive in the future, cash in an amount equal to such allowed Priority Tax Claims;

•Holders of allowed secured claims other than Priority Tax Claims or secured claims related to the DIP Facilities (“Other Secured Claims”) have received or will receive cash in an amount equal to such Other Secured Claims;

•Holders of allowed claims other than administrative expense claims or Priority Tax Claims, entitled to priority in payment as specified in section 507(a)(3), (4), (5), (6), (7), or (9) of the Bankruptcy Code (“Priority Non-Tax Claims”) have received or will receive cash in an amount equal to such allowed Priority Non-Tax Claims;

•PG&E Corporation and the Utility will pay in full all pre-petition unsecured claims that do not fall within any of the other classes of unsecured claims under the Plan (“General Unsecured Claims”) that are allowed in the Chapter 11 Cases; and

•PG&E Corporation and the Utility will pay in full all allowed claims that are subject to subordination under section 510(b) of the Bankruptcy Code other than subordinated claims related to the common stock of PG&E Corporation (“Subordinated Debt Claims”). PG&E Corporation will provide to each holder of an allowed claim that relates to the common stock of PG&E Corporation that is subject to subordination under section 510(b) of the Bankruptcy Code (a “HoldCo Rescission or Damage Claim”) a number of shares of PG&E Corporation common stock based on a formula as specified in the Plan that varies depending on when the claimant purchased the affected shares of common stock and reduces the amount of the allowed claim by the amount of insurance proceeds, if any, received by the claimant on account of all or any portion of an allowed HoldCo Rescission or Damage Claim.

In addition, the Plan also provides for the following in connection with or following the implementation of the Plan:

•Holders of claims related to the 2016 Ghost Ship fire are entitled to pursue their claims against PG&E Corporation and the Utility (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);

•Holders of certain claims may be able to pursue their claims against PG&E Corporation and the Utility, such as administrative expense claims that have not been satisfied or come due by the Effective Date, claims arising from wildfires occurring after the Petition Date that have not been satisfied by the Effective Date (including the 2019 Kincade fire (as defined in Note 14 below)), and claims relating to certain FERC refund proceedings, workers’ compensation benefits and certain environmental claims;

•PG&E Corporation or the Utility, as applicable, assumed all of their respective power purchase agreements and community choice aggregation servicing agreements; and

•PG&E Corporation or the Utility, as applicable, assumed all of their respective pension obligations, other employee obligations, and collective bargaining agreements with labor.
The Confirmation Order contains a channeling injunction that is also in the Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Claims will be from the Subrogation Wildfire Trust and the sole source of recovery for holders of Fire Victim Claims will be from the Fire Victim Trust. The holders of such claims will have no recourse to or claims whatsoever against PG&E Corporation and the Utility or their assets and properties on account of such claims.

The Plan as confirmed by the Confirmation Order provides for certain financing transactions as follows:

•one or more equity offerings of up to $9.0 billion of gross proceeds in cash through the issuance of common stock and/or other equity and/or equity-linked securities pursuant to one or more offerings and/or private placements;

•the issuance of $4.75 billion of new PG&E Corporation debt;

•the reinstatement of $9.575 billion of pre-petition debt of the Utility; and

•the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of the Utility’s 4.55% Senior Notes due 2030 and 4.95% Senior Notes due 2050 (the “New Utility Long-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (ii) $1.75 billion of the Utility’s 3.45% Senior Notes due 2025 and 3.75% Senior Notes due 2028 (the “New Utility Short-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (iii) $3.9 billion of the Utility’s 3.15% Senior Notes due 2026 and 4.50% Senior Notes due 2040 (the “New Utility Funded Debt Exchange Bonds”) to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date) (see Note 5 below for a description of the debt transactions that occurred on or before the Effective Date).

The foregoing financing transactions occurred on or around the Effective Date.

On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility paid the first tranche of tax benefits of approximately $758 million pursuant to the Tax Benefits Payment Agreement.

Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust (the “Fire Victim Trust Assignment Agreement”), pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477.0 million shares of PG&E Corporation common stock. As a result of the Additional Units Issuance (as described in Note 6 below) on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement.

Further, on the Effective Date, PG&E Corporation and the Utility funded a $10 million fund established for the benefit of the Supporting Public Entities (refer to “Plan Support Agreements with Public Entities” in Note 14 below) under the PSAs in accordance with the terms of the Plan and the PSAs with the Supporting Public Entities, and also made a payment of $1.0 billion in cash to the public entities who are party to the PSAs with the Supporting Public Entities. Also, on the Effective Date, PG&E Corporation and the Utility funded $100 million to the Subrogation Wildfire Trust and placed the balance of the $11.0 billion in a segregated escrow account established and owned by the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims, which was subsequently paid to the Subrogation Wildfire Trust.

Equity Financing

In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments. For more information, see Note 6 below.
Equity Backstop Commitments and Forward Stock Purchase Agreements

As of March 6, 2020, PG&E Corporation entered into Chapter 11 Plan Backstop Commitment Letters (collectively, as amended by the Consent Agreements (as defined below), the “Backstop Commitment Letters”) with the Backstop Parties, pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). As a result of PG&E Corporation emerging from Chapter 11 on July 1, 2020, the Backstop Commitments were not utilized and terminated in accordance with their terms.

The commitment premium for the Backstop Commitments was paid in shares (the “Backstop Commitment Premium Shares”) of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119 million shares of PG&E Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12.0 billion). PG&E Corporation issued the Backstop Commitment Premium Shares to the Backstop Parties on the Effective Date in connection with emerging from Chapter 11.

On June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of expense related to the Backstop Commitment Premium Shares in Reorganization items, net (as defined below). This amount was primarily based on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing price was $9.03 per share and as a result, PG&E Corporation recorded an additional $19 million expense in the third quarter of 2020.

Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters. As of December 31, 2020, PG&E Corporation recorded $49 million in professional fees and related expenses to the Backstop Parties in Reorganization items, net.

In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the transactions contemplated by the Plan (the “Offerings”), up to $523 million was issuable pursuant to customary options granted to the underwriters thereof to purchase the Option Securities (as defined below in Note 6).

On June 19, 2020, PG&E Corporation entered into the Forward Stock Purchase Agreements with the Backstop Parties. Each Forward Stock Purchase Agreement provided that, subject to certain conditions, the Backstop Party would purchase on the Effective Date, and receive on such settlement date as designated in the Forward Stock Purchase Agreement (the “Settlement Date”) an amount of common stock of PG&E Corporation (such shares, each Backstop Party’s “Greenshoe Backstop Shares”) equal to its pro rata share of the value of the Option Securities not purchased by the underwriters (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount” and all Greenshoe Backstop Purchase Amounts in the aggregate, the “Aggregate Greenshoe Backstop Purchase Amount”), at a price per share equal to the lesser of (i) the lowest per share price of common stock sold on an underwritten basis to the public in an offering of common stock of PG&E Corporation, as disclosed on the cover page of the prospectus or prospectus supplement, and (ii) the price per share payable by the investors party to the Investment Agreement dated as of June 7, 2020 (such lesser price, the “Settlement Price”). The Settlement Price was $9.50 per share. Each Forward Stock Purchase Agreement expired on August 3, 2020.

On June 25, 2020, the Backstop Parties funded the Greenshoe Backstop Purchase Amount to PG&E Corporation in the amount of $523 million, which was recorded in Other current liabilities on the Consolidated Financial Statements. PG&E Corporation applied the proceeds of such funding to distributions under the Plan on the Effective Date. On August 3, 2020, PG&E Corporation redeemed $120.5 million of the Forward Stock Purchase Agreements payable in cash as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement (as defined below in Note 6). On August 3, 2020, PG&E Corporation delivered 42.3 million Greenshoe Backstop Shares to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that was not redeemed.

Additionally, each Forward Stock Purchase Agreement provided that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation would issue to each Backstop Party its pro rata share of 50 million shares of common stock (such shares, each Backstop Party’s “Additional Backstop Premium Shares”). The Additional Backstop Premium Shares were issued to Backstop Parties on the Effective Date. On June 30, 2020, PG&E Corporation recorded $444 million of expense related to the Additional Backstop Premium Shares in Reorganization items, net. This amount was based primarily on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a result, PG&E Corporation recorded an additional $8 million expense in the third quarter of 2020.
Financial Reporting in Reorganization

Effective on the Petition Date and up to June 30, 2020, PG&E Corporation and the Utility applied accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that were directly associated with reorganization proceedings must have been reported separately as reorganization items, net in the Consolidated Statements of Income. In addition, the balance sheet must have distinguished pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that were not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that were not debtors in the Chapter 11 Cases in the Consolidated Balance Sheets. LSTC are pre-petition obligations that were not fully secured and had at least a possibility of not being repaid at the full claim amount. Where there was uncertainty about whether a secured claim would be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility classified the entire amount of the claim as LSTC.

Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Pursuant to the Plan and Confirmation Order, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date were subject to an injunction and were subject to treatment under the Plan. These claims were reflected as LSTC in the Consolidated Balance Sheets at December 31, 2019. Additional claims may arise for contingencies and other unliquidated and disputed amounts.

PG&E Corporation’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

The Utility’s Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

Upon emergence from Chapter 11 on July 1, 2020, PG&E Corporation and the Utility were not required to apply fresh start accounting based on the provisions of ASC 852 since the entity’s reorganization value immediately before the date of confirmation was more than the total of all its post-petition liabilities and allowed claims.

Liabilities Subject to Compromise

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities was subject to compromise or other treatment pursuant to the Plan. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are subject to an injunction and will be satisfied pursuant to the Plan and the Chapter 11 claims reconciliation process.

Prior to June 30, 2020, pre-petition liabilities that were subject to compromise were required to be reported at the amounts expected to be allowed. Therefore, liabilities subject to compromise as of December 31, 2019 in the table below reflected management’s estimates of amounts expected to be allowed in the Chapter 11 Cases, based upon, among other things, the status of negotiations with creditors. As of June 30, 2020, such amounts were reclassified to current or non-current liabilities in the Condensed Consolidated Balance Sheets, based upon management’s judgment as to the timing for settlement of such liabilities.
Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified as of December 31, 2020 consist of the following:
(in millions)Utility
PG&E
Corporation (1)
December 31, 2019
PG&E
Corporation
Consolidated
Change in Estimated Allowed Claim 2020 (2)
Cash
Payment
Reclassified as of June 30, 2020 (3)
Utility
PG&E
Corporation (1)
December 31, 2020
PG&E
Corporation
Consolidated
Financing debt
$22,450 $666 $23,116 $351 $— $(23,467)$— $— $— 
Wildfire-related claims
25,548 — 25,548 18 (23)(25,543)— — — 
Trade creditors (4)
1,183 5 1,188 6 (14)(1,180)— — — 
Non-qualified benefit plan20 137 157 — — (157)— — — 
2001 bankruptcy disputed claims234 — 234 4 — (238)— — — 
Customer deposits & advances71 — 71 12 — (83)— — — 
Other230 2 232 59 — (291)— — — 
Total Liabilities Subject to Compromise$49,736 $810 $50,546 $450 $(37)$(50,959)$— $— $— 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims,” “customer deposits & advances,” and “other” line items which are mainly due to the adjustment to recorded liabilities.
(3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets.
(4) As of February 18, 2021, $5 million and $941 million has been repaid by PG&E Corporation and the Utility, respectively.

Chapter 11 Claims Process

PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including asserted litigation claims, trade creditor claims, non-qualified benefit plan claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order.

The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation and the Utility on or after the Effective Date, including, but not limited to, the following:

•claims arising after the January 29, 2019 Petition Date that constitute administrative expense claims, which will not be discharged pursuant to the Plan, other than allowed administrative expense claims that have been paid in cash or otherwise satisfied in the ordinary course in an amount equal to the allowed amount of such claim on or prior to the Effective Date;

•claims of the Ghost Ship fire litigation (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);

•claims arising out of or based on the 2019 Kincade fire (as defined in Note 14 below), which the California Department of Forestry and Fire Protection has determined was caused by the Utility’s transmission lines; which is currently under investigation by the CPUC and the Sonoma County District Attorney’s Office; and which may also be under investigation by various other entities, including law enforcement agencies; and

•certain FERC refund proceedings, workers’ compensation benefits and environmental claims.
Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Effective Date, including but not limited to, claims arising from or relating to:

•the purported de-energization securities class action filed in October 2019 and amended to add PG&E Corporation in April 2020. For more information on the filing, see Note 14 below;

•the purported PSPS class action filed in December 2019 and seeking up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid, was dismissed on April 3, 2020, and subsequently appealed on April 6, 2020. For more information on the filing, see Note 15 below; and

•indemnification or contributing claims, including with respect to the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

In addition, claims continue to be pursued against PG&E Corporation and the Utility and certain of their respective current and former directors and officers as well as certain underwriters, in connection with three purported securities class actions, as further described in Note 14 under the heading “Securities Class Action Litigation.”

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. Pursuant to the Plan, on and after the Effective Date, the holders of such claims are entitled to pursue their claims against the Reorganized Utility as if the Chapter 11 Cases had not been commenced.

On September 1, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court requesting that the court approve an alternative dispute resolution process for resolving disputed general unsecured claims and appoint a panel of mediators in the process. On September 25, 2020, the court approved the motion and appointed a panel of mediators. The mediators’ role will be to assist various claims through a Standard and Abbreviated Mediation Process.

On October 27, 2020, PG&E Corporation and the Utility filed a motion for entry of an order extending deadline for the reorganized debtors to object to claims, requesting an additional 180 days beyond December 31, 2020 to process claims. On November 17, 2020, the Bankruptcy Court entered an order extending the deadline under the Plan for PG&E Corporation and the Utility to object to claims through and including June 26, 2021 (March 31, 2021, for claims held by the United States), without prejudice to the rights of PG&E Corporation and the Utility to seek additional extensions thereof.
Reorganization Items, Net

Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $102 million and $400 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2020 as compared to $15 million and $223 million for PG&E Corporation and the Utility, respectively, during 2019. Of the $400 million in cash paid for the Utility’s reorganization items, during the year ended December 31, 2020, $35 million in facility fees related to the Backstop Commitment Letters were recorded to a regulatory asset as they were deemed probable of recovery. Reorganization items, net for the year ended December 31, 2020 include the following:
Year Ended December 31, 2020
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$6 $— $6 
Legal and other (2)
318 1,651 1,969 
Interest and other(14)(2)(16)
Total reorganization items, net$310 $1,649 $1,959 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees.

Reorganization items, net from the Petition Date through December 31, 2019 include the following:
Petition Date Through December 31, 2019
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$97 $17 $114 
Legal and other273 19 292 
Interest income(50)(10)(60)
Total reorganization items, net$320 $26 $346 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 12 Months Ended
Dec. 31, 2020
Accounting Policies [Abstract]  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Loss Contingencies

A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which generally occur every three or four years.  The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
The following table presents the Utility’s revenues disaggregated by type of customer:
Year Ended
(in millions)20202019
Electric
Revenue from contracts with customers
   Residential$5,523 $4,847 
   Commercial4,722 4,756 
   Industrial1,530 1,493 
   Agricultural1,471 1,106 
   Public street and highway lighting69 67 
   Other (1)
(130)168 
      Total revenue from contracts with customers - electric13,185 12,437 
Regulatory balancing accounts (2)
673 303 
Total electric operating revenue$13,858 $12,740 
Natural gas
Revenue from contracts with customers
   Residential$2,517 $2,325 
   Commercial597 605 
   Transportation service only1,211 1,249 
   Other (1)
61 123 
      Total revenue from contracts with customers - gas4,386 4,302 
Regulatory balancing accounts (2)
225 87 
Total natural gas operating revenue4,611 4,389 
Total operating revenues$18,469 $17,129 
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.

Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  As of December 31, 2020, the Utility also holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.

Allowance for Doubtful Accounts Receivable and Credit Losses

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectible customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

In addition, upon adopting ASU 2016-13, PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. See “Financial Instruments - Credit Losses” below for more information.

Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations.  Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets.  Costs are carried at weighted-average and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
 Estimated UsefulBalance at December 31,
(in millions, except estimated useful lives)Lives (years)20202019
Electricity generating facilities (1)
5 to 75
$13,751 $13,189 
Electricity distribution facilities
10 to 70
37,675 35,237 
Electricity transmission facilities
15 to 75
15,556 14,281 
Natural gas distribution facilities
20 to 60
15,133 14,236 
Natural gas transmission and storage facilities
5 to 66
9,002 8,452 
Construction work in progress 2,757 2,675 
Other18 18 
Total property, plant, and equipment 93,892 88,088 
Accumulated depreciation (27,756)(26,453)
Net property, plant, and equipment
 $66,136 $61,635 
(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 15 below.)

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.76% in 2020, 3.80% in 2019, and 3.82% in 2018.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $35 million and $140 million during 2020, $55 million and $79 million during 2019, and $53 million and $129 million during 2018.
Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2020 and 2019, including nuclear decommissioning obligations:
(in millions)20202019
ARO liability at beginning of year$5,854 $5,994 
Liabilities incurred in the current period268 — 
Revision in estimated cash flows53 (376)
Accretion265 274 
Liabilities settled(28)(38)
ARO liability at end of year$6,412 $5,854 

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements. 

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation accrued was $5.1 billion and $4.9 billion at December 31, 2020 and 2019, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2020 and 2019.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.  

Consolidated VIE

The SPV is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program (as defined in Note 5 below), the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated.

The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2020 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2020, the SPV has $2.6 billion of net accounts receivable and has outstanding borrowings of $1.0 billion under the Receivables Securitization Program.

Non-Consolidated VIEs

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2020, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2020, it did not consolidate any of them.

Contributions to the Wildfire Fund

On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of December 31, 2020, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

As of December 31, 2020, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire fund asset, and $5.8 billion in non-current assets - Wildfire fund asset in the Consolidated Balance Sheets. As of December 31, 2020, the Utility recorded amortization and accretion expense of $413 million. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire fund expense in the Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.
AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation results in the estimated number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Starting with a 5-year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a 10% change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ service territories in 2020 for which the cause is currently unknown and which may in the future be determined to be covered by the Wildfire Fund. At December 31, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s and the Utility’s Consolidated Financial Statements, see “Income Taxes” in Note 9, “Derivatives” in Note 10, “Fair Value Measurements” in Note 11, and “Contingencies and Commitments” in Notes 14 and 15 herein.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits		Total
Beginning balance$(22)$17 $(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)
(417)170 (247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)
400 (170)230 
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)
(4)10 6 
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively) (1)
2 (15)(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)
2 5 7 
Net current period other comprehensive loss(17)— (17)
Ending balance$(39)$17 $(22)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 12 below for additional details.) 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2019 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits		Total
Beginning balance$(21)$17 $(4)
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss (net of taxes of $24 and $88, respectively)
61 227 288 
Regulatory account transfer (net of taxes of $24 and $88, respectively)
(62)(227)(289)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)
(4)10 6 
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)
2 (2)— 
Regulatory account transfer (net of taxes of $1 and $3, respectively) (1)
2 (8)(6)
Net current period other comprehensive loss(1)— (1)
Ending balance$(22)$17 $(5)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 12 below for additional details.)

Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.
Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets. Financing leases were immaterial for the years ended December 31, 2020 and 2019.

For the years ended December 31, 2020 and 2019, the Utility made total cash payments, including fixed and variable, of $2.5 billion and $2.4 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.

At December 31, 2020 and 2019, the Utility’s operating leases had a weighted average remaining lease term of 5.7 years and 5.9 years and a weighted average discount rate of 6.2% and 6.2%, respectively.

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:
Year Ended December 31,
(in millions)20202019
Operating lease fixed cost$679 $686 
Operating lease variable cost1,852 1,778 
Total operating lease costs$2,531 $2,464 

At December 31, 2020, the Utility’s future expected operating lease payments were as follows:
(in millions)December 31, 2020
2021$624 
2022550 
2023257 
202498 
202591 
Thereafter513 
Total lease payments2,133 
Less imputed interest(397)
Total$1,736 

Recently Adopted Accounting Standards

Intangibles—Goodwill and Other

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures.
Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses On Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. PG&E Corporation and the Utility adopted the ASU on January 1, 2020.

PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. As of December 31, 2020, expected credit losses of $150 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded at December 31, 2020, $76 million and $10 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.

Defined Benefit Plans

In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for defined benefit plans. PG&E Corporation and the Utility adopted the ASU as of December 31, 2020. The adoption of ASU 2018-14 resulted in elimination of the disclosures of (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the (1) aggregate of the service and interest cost components of net periodic benefit costs and (2) benefit obligation for postretirement health care benefits. Additionally, the adoption of this ASU resulted in new disclosures of (i) the weighted-average interest crediting rates for cash balance plans and (ii) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. These amendments have been applied on a retrospective basis to all periods presented. See Note 12 below for further discussion of PG&E Corporation’s and the Utility’s defined benefit pension plans.

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. This ASU became effective for PG&E Corporation and the Utility on January 1, 2021 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.
Debt

In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.
v3.20.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
 12 Months Ended
Dec. 31, 2020
Regulated Operations [Abstract]  
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets

Long-term regulatory assets are comprised of the following:
 Balance at December 31,Recovery
Period
(in millions)20202019
Pension benefits (1)
$2,245 $1,823 Indefinitely
Environmental compliance costs1,112 1,062 32 years
Utility retained generation (2)
181 228 6 years
Price risk management204 124 19 years
Unamortized loss, net of gain, on reacquired debt
49 63 23 years
Catastrophic event memorandum account (3)
842 656 
1 - 3 years
Wildfire expense memorandum account (4)
400 423 
1 - 3 years
Fire hazard prevention memorandum account (5)
137 259 
1 - 3 years
Fire risk mitigation memorandum account (6)
66 95 
1 - 3 years
Wildfire mitigation plan memorandum account (7)
390 558 
1 - 3 years
Deferred income taxes (8)
908 252 51 years
Insurance premium costs (9)
294 — 
1 - 4 years
Wildfire mitigation balancing account (10)
156 — 
1 - 3 years
General rate case memorandum accounts (11)
376 — 
1 - 2 years
Vegetation management balancing account (12)
592 — 
1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)
84 — TBD years
Other942 523 Various
Total long-term regulatory assets$8,978 $6,066  
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. 
(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval.
(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.
(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval.
(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020. Recovery of WMPMA costs is subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.
(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2020. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
(11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through the date of the final 2020 GRC decision as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 17 months, beginning March 1, 2021.
(12) The 2020 GRC Decision authorized the Utility to modify the existing one-way VMBA Expense Balancing Account to a two-way balancing account to track the difference between actual and adopted expenses resulting from its routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.
(13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2020, the Utility had recorded an aggregate under-collection of $76 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $8 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:
 Balance at December 31,
(in millions)20202019
Cost of removal obligations (1)
$6,905 $6,456 
Recoveries in excess of AROs (2)
458 393 
Public purpose programs (3)
948 817 
Employee benefit plans (4)
995 750 
Other1,118 854 
Total long-term regulatory liabilities
$10,424 $9,270 
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 11 below.)
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans.

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable
Balance at December 31,
(in millions)20202019
Electric transmission$— $9 
Gas distribution and transmission102 363 
Energy procurement413 901 
Public purpose programs292 209 
Fire hazard prevention memorandum account121 — 
Fire risk mitigation memorandum account
33 — 
Wildfire mitigation plan memorandum account161 — 
Wildfire mitigation balancing account27 — 
General rate case memorandum accounts313 — 
Vegetation management balancing account115 — 
Insurance premium costs135 — 
Other289 632 
Total regulatory balancing accounts receivable$2,001 $2,114 

Payable
Balance at December 31,
(in millions)20202019
Electric distribution$55 $31 
Electric transmission267 119 
Gas distribution and transmission76 45 
Energy procurement158 649 
Public purpose programs410 559 
Other279 394 
Total regulatory balancing accounts payable$1,245 $1,797 

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency. The FHPMA tracks costs that protect the public from potential fire hazards. The FRMMA and WMPMA balances track costs that are recoverable within 12 months as requested in the 2020 WMCE application. The WMBA tracks costs associated with wildfire mitigation revenue requirement activities. The general rate case memorandum accounts track the difference between the revenue requirements in effect on January 1, 2020 and the revenue requirements authorized by the CPUC in the 2020 GRC Decision in December 2020. The VMBA tracks routine and enhanced vegetation management activities. The insurance premium costs track the current portion of incremental excess liability insurance costs recorded to RTBA and adjustment mechanism for costs determined in other proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. In addition to insurance premium costs recorded in Regulatory balancing accounts receivable and in Long-term regulatory assets above, at December 31, 2020, there was $93 million in insurance premium costs recorded in Current regulatory assets.
v3.20.4
DEBT
 12 Months Ended
Dec. 31, 2020
Debt Disclosure [Abstract]  
DEBT DEBT
Debtor-In-Possession Facilities

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPM, as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto.
On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2020:
(in millions)Termination
Date		Facility LimitBorrowings OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJuly 2023$3,500 
(1)
$605 $1,020 $1,875 
Utility term loan credit facility
Various(2)
3,000 3,000 — — 
Utility receivables securitization programOctober 20221,000 1,000 — — 
PG&E Corporation revolving credit facilityJuly 2023500 — — 500 
Total credit facilities$8,000 $4,605 $1,020 $2,375 
(1) Includes a $1.5 billion letter of credit sublimit.
(2) This includes a $1.5 billion term loan credit facility with a maturity date of June 30, 2021 and a $1.5 billion term loan credit facility with a maturity date of January 1, 2022.

Utility

Utility Revolving Credit Facility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM, and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two one-year extensions options.

Borrowings under the Utility Revolving Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 1.375% to 2.50% based on the Utility’s credit rating or (2) the base rate plus an applicable margin of 0.375% to 1.50% based on the Utility’s credit rating. In addition to interest on outstanding principal under the Utility Revolving Credit Agreement, the Utility is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.25% to 0.50% per annum depending on the Utility’s credit rating. The Utility Revolving Credit Agreement has a maximum letter of credit sublimit equal to $1.5 billion. The Utility may also pay customary letter of credit fees based on letters of credit issued under the Utility Revolving Credit Agreement.

The Utility’s obligations under the Utility Revolving Credit Agreement are secured by the issuance of a first mortgage bond, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.

The Utility Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, and (4) fundamental changes. In addition, the Utility Revolving Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Revolving Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the designated agent may, with the consent of the required lenders (or shall upon the request of the required lenders), declare the amounts outstanding under the Utility Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Agreement become payable immediately.

The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary prepayments made by the Utility will not reduce the commitments under the Utility Revolving Credit Agreement.
Utility Term Loan Credit Facility

On July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent. The credit facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund, in part, transactions contemplated under the Plan.

Borrowings under the Utility Term Loan Credit Agreement bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 2.00% with respect to the Utility 364-Day Term Loan Facility and 2.25% with respect to the Utility 18-Month Term Loan Facility, or (2) the base rate plus an applicable margin of 1.00% with respect to the Utility 364-Day Term Loan Facility and 1.25% with respect to the Utility 18-Month Term Loan Facility.

The Utility’s obligations under the Utility Term Loan Credit Agreement are secured by the issuance of first mortgage bonds, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.

The Utility Term Loan Credit Agreement includes usual and customary provisions for term loan agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) fundamental changes, (5) entering into swap agreements and (6) modifications to the Utility’s mortgage indenture. In addition, the Utility Term Loan Credit Agreement requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of December 31, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Term Loan Credit Agreement, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Utility Term Loan Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Term Loan Credit Agreement become payable immediately.

The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Agreement (with all outstanding term loans made under the Utility 364-Day Term Loan Facility being paid first), subject to certain exceptions, with 100% of the net cash proceeds of certain securitization transactions. The Utility may voluntarily repay outstanding loans under the Utility Term Loan Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans.

Receivables Securitization Program

On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time.
The loans under the Receivables Securitization Program bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate.  The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events.

The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable.

In general, the proceeds from the sale of the accounts receivable are used by the SPV to pay the purchase price for accounts receivables it acquires from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses.

Although the SPV is a wholly owned consolidated subsidiary of the Utility, the SPV is legally separate from the Utility. The assets of the SPV (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program is accounted for as a secured financing. The pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets.

At December 31, 2020 the Utility had outstanding borrowings of $1.0 billion under the Receivables Securitization Program.

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two one-year extensions at the option of PG&E Corporation. The proceeds from the loans under the Corporation Revolving Credit Agreement will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

Borrowings under the Corporation Revolving Credit Agreement bear interest based on PG&E Corporation’s election of either (1) LIBOR plus an applicable margin of 3.00% to 4.25% based on PG&E Corporation’s credit rating or (2) the base rate plus an applicable margin of 2.00% to 3.25% based on PG&E Corporation’s credit rating. In addition to interest on outstanding principal under the Corporation Revolving Credit Agreement, PG&E Corporation is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.50% to 0.75% per annum depending on PG&E Corporation’s credit rating.

PG&E Corporation’s obligations under the Corporation Revolving Credit Agreement are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

The Corporation Revolving Credit Agreement includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) investments, (5) dispositions, (6) changes in the nature of business, (7) transactions with affiliates, (8) burdensome agreements, (9) restricted payments, (10) fundamental changes, (11) use of proceeds, (12) entering into swap agreements and (13) the ability to dispose of common stock of the Utility. In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.
In the event of a default by PG&E Corporation under the Corporation Revolving Credit Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Corporation Revolving Credit Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Agreement become payable immediately.

PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Agreement at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary repayments made by PG&E Corporation will not reduce the commitments under the Corporation Revolving Credit Agreement.

On the Effective Date, PG&E Corporation repaid and terminated $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent.

Other Short-term Borrowings

On November 16, 2020, the Utility completed the sale of $1.45 billion aggregate principal amount of floating rate first mortgage bonds due November 15, 2021. Proceeds from the sale of the mortgage bonds were used for general corporate purposes, including the repayment of borrowings outstanding under the Receivables Securitization Program and borrowings outstanding under the Utility Revolving Credit Facility.

Long-Term Debt

Utility

On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1.0 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2.0 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1.0 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and between the Escrow Agent and the Utility. On July 1, 2020, the net proceeds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.

On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt, as described in the table below.

On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes.

The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first priority lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture.

On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated.

In addition, on July 1, 2020, the Utility obtained a $1.5 billion 18-month secured term loan under the Utility Term Loan Credit Agreement. For more information, see “Credit Facilities” discussion above.
PG&E Corporation

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “PG&E Corporation Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”) with JPM, and other lenders from time to time party thereto (collectively, the “Lenders”), JPM, as Administrative Agent and as Collateral Agent. The proceeds of the PG&E Corporation Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation and subsequently released from escrow on the Effective Date pursuant to the Plan.

On February 1, 2021, PG&E Corporation entered into a repricing amendment (the “Repricing Amendment”) with the lenders under the Term Loan Credit Agreement pursuant to which, among other things, the applicable interest rate was reduced.

In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the PG&E Corporation Term Loan in an amount equal to $6.875 million on the last business day of each quarter. The PG&E Corporation Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The PG&E Corporation Term Loan bears interest based, at PG&E Corporation’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. The original LIBOR floor was 1.0% but was reduced to 0.5% on February 1, 2021 in connection with the Repricing Amendment. The original ABR floor was 2.0% but was similarly reduced to 1.5% on February 1, 2021 in connection with the Repricing Amendment. ABR will equal the highest of the following: the prime rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus 1.0%. The applicable margin for LIBOR loans is 3.0% (reduced from 4.5% on February 1, 2021 in connection with the Repricing Amendment) and the applicable margin for ABR loans is 2.0% (reduced from 3.5% on February 1, 2021 in connection with the Repricing Amendment). PG&E Corporation may prepay the PG&E Corporation Term Loan in whole, at any time, and in part, from time to time, without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans; provided, however, that any voluntary prepayment, refinancing or repricing of the PG&E Corporation Term Loan in connection with certain repricing transactions that occur on or prior to August 1, 2021 shall be subject to a prepayment premium of 1.0% of the principal amount of the term loans so prepaid, refinanced or repriced.

The Term Loan Agreement includes usual and customary covenants for loan agreements of this type, including covenants limiting: (1) liens, (2) mergers, (3) sales of all or substantially all of PG&E Corporation’s assets, and (4) sale and leaseback transactions. In addition, the Term Loan Agreement requires that PG&E Corporation maintain ownership, either directly or indirectly, through one or more subsidiaries, of at least 100% of the outstanding common stock of the Utility.

In the event of a default by PG&E Corporation under the Term Loan Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the Administrative Agent may, with the consent of the required Lenders (or upon the request of the required Lenders, shall), declare the amounts outstanding under the Term Loan Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Term Loan Agreement become payable immediately.

On the Effective Date, the obligations under the Term Loan Agreement became secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On July 1, 2020, the net proceeds from the PG&E Corporation Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.

Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (the “2030 Notes,” and together with the 2028 Notes, the “Notes”). The proceeds of the Notes were initially deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and PG&E Corporation. Prior to July 1, 2023, in the case of the 2028 Notes, and prior to July 1, 2025, in the case of the 2030 Notes, (i) PG&E Corporation may redeem all or part of the Notes of the applicable series, on any one or more occasions at a redemption price equal to 100% of the principal amount of Notes of such series to be redeemed, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the redemption date or (ii) PG&E Corporation may redeem up to 40% of the aggregate principal amount of the Notes of the applicable series on any one or more occasions at certain specified redemption prices with the net cash proceeds from certain equity offerings. On or after July 1, 2023, in the case of the 2028 Notes, and July 1, 2025, in the case of the 2030 Notes, PG&E Corporation may redeem the Notes of a series at certain specified redemption prices, plus accrued and unpaid interest thereon, if any, to but not including, the applicable redemption date.
On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

On the Effective Date, PG&E Corporation repaid and terminated $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
Balance at
(in millions)
Contractual Interest Rates (3)
December 31, 2020December 31, 2019
Treatment under Plan on the Effective Date (1)
Pre-Petition Debt (2)
PG&E Corporation
Borrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022
variable rate (4)
$— $300 
Repaid in cash (14)
Other borrowings
Term Loan - Stated Maturity: 2020
 variable rate (5)
— 350 
Repaid in cash (14)
Total PG&E Corporation Pre-Petition Long-Term Debt— 650 
Utility
Senior Notes - Stated Maturity:
2020 through 2022
2.45% to 4.25%
— 1,750 
Exchanged (15)
2023 through 2028
2.95% to 4.65%
— 5,025 
Reinstated (16)
2034 through 2040
5.40% to 6.35%
— 5,700 
Exchanged (17)
2041 through 2042
3.75% to 4.50%
— 1,000 
Reinstated (16)
20435.13%— 500 
Exchanged (17)
2043 through 2047
3.95% to 4.75%
— 3,550 
Reinstated (16)
Total Pre-Petition Senior Notes— 17,525 
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026
1.75%— 100 
Repaid in cash (14)
Series 2009 A-B, due 2026
variable rate (6)
— 149 
Exchanged (18)
Series 1996 C, E, F, 1997 B due 2026
variable rate (7)
— 614 
Exchanged (18)
Total Pre-Petition Pollution Control Bonds— 863 
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022
 variable rate (8)
— 2,888 
Exchanged (18)
Other borrowings:
Term Loan - Stated Maturity: 2019
 variable rate (9)
— 250 
Exchanged (18)
Total Borrowings under Pre-Petition Credit Facility— 3,138 
Total Utility Pre-Petition Debt— 21,526 
Total PG&E Corporation Consolidated Pre-Petition Debt$— $22,176 
New Long-Term Debt
PG&E Corporation
Term Loan - Stated Maturity: 2025
variable rate (10)
$2,709 $— 
Senior Secured Notes due 20285.00%1,000 — 
Senior Secured Notes due 20305.25%1,000 — 
Unamortized discount, net of premium and debt issuance costs(85)— 
Total PG&E Corporation New Long-Term Debt4,624 — 
Utility
Pre-Petition Senior Notes Reinstated as First Mortgage Bonds - Stated Maturity:
2023 through 2028
2.95% to 4.65%
5,025 — 
2041 through 2042
3.75% to 4.50%
1,000 — 
2043 through 2047
3.95% to 4.75%
3,550 — 
Unamortized discount, net of premium and debt issuance costs— — 
Total Utility Reinstated New Long-Term Debt9,575 — 
Pre-Petition Debt Exchanged for First Mortgage Bonds - Stated Maturity:
20253.45%875 — 
20263.15%1,951 — 
20283.75%875 — 
20304.55%3,100 — 
20404.50%1,951 — 
20504.95%3,100 — 
Unamortized discount, net of premium and debt issuance costs(98)— 
Total Utility Exchanged New Long-Term Debt11,754 — 
New First Mortgage Bonds - Stated Maturity:
2022
variable rate (11)
500 — 
20221.75%2,500 — 
20272.10%1,000 — 
20312.50%2,000 — 
20403.30%1,000 — 
20503.50%1,925 — 
Unamortized discount, net of premium and debt issuance costs(84)— 
Total Utility New First Mortgage Bonds8,841 — 
Credit Facilities - Stated Maturity: 2022
Receivables securitization program
variable rate (12)
1,000 — 
18-month Term Loan
variable rate (13)
1,500 — 
Unamortized discount, net of premium and debt issuance costs(6)— 
Total Utility New Long-Term Debt32,664 — 
Total PG&E Corporation Consolidated New Long-Term Debt$37,288 $— 
(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2.
(2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court.
(3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and 2020, respectively.
(4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%.
(5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%.
(6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%.
(7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%.
(8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%.
(9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%.
(10) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 5.50%.
(11) At December 31, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.70%.
(12) At December 31, 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.57%.
(13) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 2.44%.
(14) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020.
(15) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(16) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above.
(17) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(18) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility.  Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

In accordance with the Plan, on July 1, 2020, the Utility repaid Series 2008 F and 2010 E and exchanged Series 2009 A-B, Series 1996 C, E, F, and 1997 B for first mortgage bonds.

Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2020 are reflected in the table below:
(in millions,       
except interest rates)20212022202320242025ThereafterTotal
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, 20205.50 %5.50 %5.50 %5.50 %5.50 %— %5.50 %
Variable rate obligations$28 $28 $28 $28 $2,625 $— $2,737 
Utility
Average fixed interest rate— %1.75 %3.83 %3.60 %3.47 %3.87 %3.66 %
Fixed rate obligations$— $2,500 $1,175 $800 $1,475 $23,902 $29,852 
Variable interest rate as of December 31, 2020— %
various (1)
— %— %— %— %
various (1)
Variable rate obligations
$— $3,000 $— $— $— $— $3,000 
Total consolidated debt$28 $5,528 $1,203 $828 $4,100 $25,902 $37,589 
(1) At December 31, 2020, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.57%, 1.70% and 2.44% respectively.
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION
 12 Months Ended
Dec. 31, 2020
Common Stock And Share-Based Compensation [Abstract]  
COMMON STOCK AND SHARE-BASED COMPENSATION COMMON STOCK AND SHARE-BASED COMPENSATION
PG&E Corporation had 1,984,678,673 shares of common stock outstanding at December 31, 2020.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2020.

On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. As of the termination date for this agreement, no amounts were outstanding which required repayment.

Increase in Authorized Capitalization

On June 22, 2020, PG&E Corporation filed Amended Articles of Incorporation with the Secretary of State of California which increased the authorized number of shares of common stock to 3.6 billion and the authorized number of shares of preferred stock to 400 million.
Plan Equity Financings

In connection with emergence from Chapter 11, in July 2020, PG&E Corporation raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments as described below.

PG&E Corporation Investment Agreement

On June 7, 2020, PG&E Corporation entered into an Investment Agreement (the “Investment Agreement”) with certain investors (the “Investors”) relating to the issuance and sale to the Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock. Per the Investment Agreement, the price per share was equal to $9.50 per share, which was the public equity offering price in the Common Stock Offering (as defined below in “Equity Offerings”).

On July 1, 2020, pursuant to the terms of the Investment Agreement, PG&E Corporation issued to the Investors 342.1 million shares of common stock. The Investors and their affiliates have certain customary registration rights with respect to the Shares held by such Investor pursuant to the terms of the Investment Agreement.

Equity Offerings

On June 25, 2020, PG&E Corporation priced (i) the Common Stock Offering of 423.4 million shares of its common stock, and (ii) the concurrent Equity Units Offering of 14.5 million of its Equity Units, for total net proceeds to PG&E Corporation, after deducting the underwriting discounts and before estimated offering expenses payable by the PG&E Corporation, of $3.97 billion and $1.19 billion, respectively.

On June 25, 2020, in connection with the Common Stock Offering, PG&E Corporation entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of several underwriters named in the Common Stock Underwriting Agreement (the “Common Stock Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 423.4 million shares of its common stock to the Common Stock Underwriters. In addition, on June 25, 2020, PG&E Corporation entered into an underwriting agreement (the “Equity Units Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Equity Units Underwriting Agreement (the “Equity Units Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 14.5 million prepaid forward stock purchase contracts (the “Purchase Contracts”) to the Equity Underwriters in order for the Equity Units Underwriters to sell 14.5 million Equity Units.

In connection with the Common Stock Offering and pursuant to the Common Stock Underwriting Agreement, PG&E Corporation granted the underwriters a 30-day over-allotment option to purchase up to an additional 42.3 million shares of common stock. In addition, in connection with the Equity Units Offering and pursuant to the Equity Units Underwriting Agreement, PG&E Corporation also granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.45 million Purchase Contracts to be used by the Equity Units Underwriters to create up to an additional 1.45 million Equity Units (together with the 42.3 million shares of common stock, the “Option Securities”).

The Common Stock Offering and the Equity Units Offering closed on July 1, 2020, and PG&E Corporation issued and sold a total of 423.4 million shares of its common stock and 14.5 million Purchase Contracts for total net proceeds of $5.2 billion. On July 24, 2020, the Equity Units Underwriters exercised in full, the over-allotment option in the Equity Units Underwriting Agreement and on August 3, 2020, PG&E Corporation issued and sold 1.45 million Equity Units to the Equity Units Underwriters (the “Additional Units Issuance”). The prepaid forward stock purchase contract portion of the Equity Units issued in the Equity Units Offering and the Additional Units Issuance represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided herein. The settlement date of the purchase contract is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. The Common Stock Underwriters did not exercise their option to purchase any additional shares of common stock.
PG&E Corporation applied accounting standards applicable to prepaid forward contracts to purchase common stock in order to determine the proper balance sheet classification for the Equity Units issued and sold during the three months ended, September 30, 2020. The Equity Units are considered a range forward contract, in that the settlement of common stock shares is based on a range of potential settlement outcomes. PG&E Corporation used various inputs, including stock price volatility, and determined that the potential outcomes are predominantly fixed share settlements. As such, PG&E Corporation does not view the Equity Units as an obligation to issue a variable number of shares and has concluded that the Equity Units meet all conditions for equity classification and do not meet any of the other conditions that would result in asset or liability classification. The Equity Units issued and sold are classified as Common stock on PG&E Corporation’s Consolidated Balance Sheet.

Equity Backstop Commitments and Forward Stock Purchase Agreements

See “Equity Financing” in Note 2 above for discussion of the equity backstop commitments which resulted in total net proceeds of $523 million (of which $120.5 million were returned to the Backstop Parties pursuant to the Forward Stock Purchase Agreements, as described below).

In connection with the Additional Units Issuance and pursuant to the terms of the Forward Stock Purchase Agreements, on August 3, 2020, PG&E Corporation (i) redeemed a portion of the rights under the Forward Stock Purchase Agreements to receive shares of Common Stock and returned approximately $120.5 million to the Backstop Parties and (ii) issued and delivered to the Backstop Parties 42.3 million Greenshoe Backstop Shares, representing the unredeemed portion of the Aggregate Greenshoe Backstop Purchase Amount divided by the Settlement Price (without any issuance in respect of fractional shares).

Equity Issuances to the Fire Victim Trust

On the Effective Date, pursuant to the Plan, the Utility entered into the Fire Victim Trust Assignment Agreement, pursuant to which the Utility transferred to the Fire Victim Trust 477 million shares of common stock of PG&E Corporation. As a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement.

Cash Contribution to the Utility Pursuant to the Plan

On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash to the Utility, which used the funds to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.

As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.
In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility issued to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. The shares transferred to the Fire Victim Trust were valued at $4.53 billion on the date of transfer, $2.2 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.

In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of December 31, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. PG&E Corporation expects to elect grantor trust treatment, subject to entering into a definitive agreement with the Fire Victim Trust. There can be no assurance that such an agreement will be reached or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur only at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were contributed to the Fire Victim Trust.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018.

On April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s WMP.

On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid.  Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s emergence from Chapter 11.  

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of December 31, 2020, it is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.
Long-Term Incentive Plan

The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  As of the Effective Date, the LTIP was amended to increase the maximum number of shares of PG&E Corporation common stock reserved for issuance under the LTIP from 17 million shares to 47 million (subject to certain adjustments), of which 29,174,205 shares were available for future awards at December 31, 2020.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2020:
(in millions)
202020192018
Stock Options$3 $7 $10 
Restricted stock units15 21 43 
Performance shares17 22 36 
Total compensation expense (pre-tax)$35 $50 $89 
Total compensation expense (after-tax)$25 $35 $63 

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2020, $0.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of 0.16 years for PG&E Corporation.

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method.  The weighted average grant date fair value of options granted using the Black-Scholes valuation method in 2019 was $3.87 per share. No stock options were granted in 2020.  The significant assumptions used for shares granted in 2019 were:
2019
Expected stock price volatility57.00 %
Expected annual dividend payment— %
Risk-free interest rate
1.51% to 1.52%
Expected life (years)4.5

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

There was no tax benefit recognized from stock options for the year ended December 31, 2020.
The following table summarizes stock option activity for PG&E Corporation and the Utility for 2020:
Number of
Stock Options		Weighted Average Grant-
Date Fair Value		Weighted Average Remaining Contractual TermAggregate Intrinsic Value
Outstanding at January 14,281,403 $5.98 $— 
Granted (1)
20,065 3.87 — 
Exercised— — — 
Forfeited or expired(2,080,221)3.87 — 
Outstanding at December 312,221,247 7.45 5.33 years— 
Vested or expected to vest at December 312,215,076 7.43 5.31 years— 
Exercisable at December 311,840,893 $6.86 4.93 years$— 
(1) Represents additional payout of existing stock option grants.

Restricted Stock Units

Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2020, 2019, and 2018 was $9.25, $18.57, and $40.92, respectively.  The total fair value of restricted stock units that vested during 2020, 2019, and 2018 was $31 million, $42 million, and $41 million, respectively.  The tax detriment from restricted stock units that vested in 2020 was $19 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2020, $6 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.58 years.

The following table summarizes restricted stock unit activity for 2020:
Number of
Restricted Stock Units		Weighted Average Grant-
Date Fair Value
Nonvested at January 11,040,835 $44.06 
Granted1,007,782 9.25 
Vested(944,090)33.14 
Forfeited(214,174)15.75 
Nonvested at December 31890,353 $23.05 

Performance Shares

Performance shares generally will vest three years after the grant date.  Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric.  Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during 2020, 2019, and 2018 was $9.62, $15.39, and $36.92 respectively.  The tax detriment from performance shares that vested in 2020 was $49 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2020, $54 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 2.2 years.
The following table summarizes activity for performance shares in 2020:
Number of
Performance Shares		Weighted Average Grant-
Date Fair Value
Nonvested at January 1688,423 $36.92 
Granted7,951,541 9.62 
Vested(132,526)41.27 
Forfeited (1)
(1,218,656)24.38 
Nonvested at December 317,288,782 $9.16 
(1) Includes performance shares that expired with zero value as performance targets were not met.
v3.20.4
PREFERRED STOCK
 12 Months Ended
Dec. 31, 2020
Preferred Stock [Abstract]  
PREFERRED STOCK PREFERRED STOCK
PG&E Corporation has authorized 400 million shares of preferred stock, none of which is outstanding.

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2020 and December 31, 2019, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share.  The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

At December 31, 2020, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2020, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  The Utility paid no dividends on preferred stock in 2020, 2019, or 2018.
v3.20.4
EARNINGS PER SHARE
 12 Months Ended
Dec. 31, 2020
Earnings Per Share [Abstract]  
EARNINGS PER SHARE EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2020, 2019, and 2018.
 Year Ended December 31,
(in millions, except per share amounts)202020192018
Loss attributable to common shareholders$(1,318)$(7,656)$(6,851)
Weighted average common shares outstanding, basic1,257 528 517 
Add incremental shares from assumed conversions:
Employee share-based compensation
— — — 
Equity Units— — — 
Weighted average common share outstanding, diluted1,257 528 517 
Total Loss per common share, diluted$(1.05)$(14.50)$(13.25)

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.
v3.20.4
INCOME TAXES
 12 Months Ended
Dec. 31, 2020
Income Tax Disclosure [Abstract]  
INCOME TAXES INCOME TAXES
PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. 

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)202020192018202020192018
Current:      
Federal$(26)$1 $(5)$(26)$4 $5 
State(34)101 (8)(34)94 (7)
Deferred:
Federal258 (2,361)(2,264)290 (2,363)(2,278)
State171 (1,136)(1,009)185 (1,137)(1,009)
Tax credits(7)(5)(6)(7)(5)(6)
Income tax provision (benefit)
$362 $(3,400)$(3,292)$408 $(3,407)$(3,295)
The following tables describe net deferred income tax assets and liabilities:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)2020201920202019
Deferred income tax assets:    
Tax carryforwards$7,641 $1,390 $7,529 $1,308 
Compensation187 151 109 92 
Wildfire-related claims (1)
544 6,520 544 6,520 
Operating lease liability
489 642 488 640 
Other (2)
212 112 219 121 
Total deferred income tax assets$9,073 $8,815 $8,889 $8,681 
Deferred income tax liabilities:    
Property related basis differences8,311 7,984 8,300 7,973 
Regulatory balancing accounts763 381 763 381 
Debt financing costs526 — 526 — 
Operating lease right of use asset489 642 488 640 
Income tax regulatory asset(3)
254 71 254 71 
Other (4)
128 57 128 58 
Total deferred income tax liabilities$10,471 $9,135 $10,459 $9,123 
Total net deferred income tax liabilities$1,398 $320 $1,570 $442 
(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred on PG&E Corporation’s and the Utility’s service territory over the past several years.
(2) Amounts include benefits, environmental reserve, and customer advances for construction. 
(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.
(4) Amount primarily includes an environmental reserve.

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
 PG&E CorporationUtility
 Year Ended December 31,
 202020192018202020192018
Federal statutory income tax rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(15.3)7.5 7.9 19.1 7.5 7.9 
Effect of regulatory treatment of fixed asset differences (2)
39.0 2.8 3.6 (44.9)2.8 3.6 
Tax credits1.5 0.1 0.1 (1.7)0.1 0.1 
Bankruptcy and emergence (3)
(82.5)— — 54.1 — — 
Other, net (4)
(2.1)(0.6)(0.1)2.2 (0.5)— 
Effective tax rate(38.4)%30.8 %32.5 %49.8 %30.9 %32.6 %
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  In 2020, 2019, and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) The Utility includes an adjustment for the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust. PG&E Corporation includes the same adjustment as the Utility and a permanent non-deductible equity backstop premium expense. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively, accounts for the remaining difference.
(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019.
Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:
 PG&E CorporationUtility
(in millions)202020192018202020192018
Balance at beginning of year$420 $377 $349 $420 $377 $349 
Reductions for tax position taken during a prior year(43)(1)(27)(43)(1)(27)
Additions for tax position taken during the current year60 44 55 60 44 55 
Settlements— — — — — — 
Expiration of statute— — — — — — 
Balance at end of year
$437 $420 $377 $437 $420 $377 

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2020 for PG&E Corporation and the Utility was $16 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2020, 2019, and 2018, these amounts were immaterial.

Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes, except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the penalty decision issued in 2015 for the San Bruno natural gas explosion in September of 2010.

Tax years after 2007 remain subject to examination by the State of California.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
(in millions)December 31, 2020Expiration
Year
Federal:  
Net operating loss carryforward - Pre-2018$3,600 2031 - 2036
Net operating loss carryforward - Post-201724,887 N/A
Tax credit carryforward134 2029 - 2040
State:
Net operating loss carryforward$25,364 2039 - 2040
Tax credit carryforward100 Various

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.
Other Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits are not likely to change significantly within the next 12 months. At December 31, 2020, it is reasonably possible that within the next 12 months, unrecognized tax benefits will decrease. The amount is not expected to be material.

As of the date of this report, PG&E Corporation does not believe that it had undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility have deferred the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022.

During June 2020, the State of California enacted AB 85, which increases taxes on corporations over a three-year period beginning in 2020 by suspension of the net operating loss deduction and a limit of $5 million per year on business tax credits. PG&E Corporation and the Utility do not anticipate any material impacts to PG&E Corporation’s Consolidated Financial Statements due to this legislation.

In December 2020, Congress passed, and the President signed into law the Consolidations and Appropriations Act of 2021. PG&E Corporation and the Utility do not expect this legislation to have a material impact to PG&E Corporation’s Consolidated Financial Statements.

See “Ownership Restrictions in PG&E Corporation’s Amended Articles” in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 for information on the possible election to treat the Fire Victim Trust as a “grantor trust” for federal income tax purposes.
v3.20.4
DERIVATIVES
 12 Months Ended
Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVES DERIVATIVES
Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Consolidated Balance Sheets at fair value. 
Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume
At December 31,
Underlying ProductInstruments20202019
Natural Gas (1) (MMBtus (2))
Forwards, Futures and Swaps146,642,863 131,896,159 
 Options14,140,000 14,720,000 
Electricity (Megawatt-hours)Forwards, Futures and Swaps9,435,830 18,675,852 
Options— — 
 
Congestion Revenue Rights (3)
266,091,470 308,467,999 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At December 31, 2020, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$33 $— $115 $148 
Other noncurrent assets – other136 — — 136 
Current liabilities – other(38)— 15 (23)
Noncurrent liabilities – other(204)— 10 (194)
Total commodity risk$(73)$— $140 $67 

At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$36 $(6)$4 $34 
Other noncurrent assets – other130 (6)— 124 
Current liabilities – other(31)6 2 (23)
Noncurrent liabilities – other(130)6 — (124)
Total commodity risk$5 $— $6 $11 

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.
Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2020, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
v3.20.4
FAIR VALUE MEASUREMENTS
 12 Months Ended
Dec. 31, 2020
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, 2020
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$470 $— $— $— $470 
Nuclear decommissioning trusts
Short-term investments27 — — — 27 
Global equity securities2,398 — — — 2,398 
Fixed-income securities924 835 — — 1,759 
Assets measured at NAV— — — — 25 
Total nuclear decommissioning trusts (2)
3,349 835 — — 4,209 
Price risk management instruments (Note 10)     
Electricity— 2 166 2 170 
Gas— 1 — 113 114 
Total price risk management instruments— 3 166 115 284 
Rabbi trusts     
Fixed-income securities— 106 — — 106 
Life insurance contracts— 79 — — 79 
Total rabbi trusts— 185 — — 185 
Long-term disability trust     
Short-term investments9 — — — 9 
Assets measured at NAV— — — — 158 
Total long-term disability trust9 — — — 167 
TOTAL ASSETS$3,828 $1,023 $166 $115 $5,315 
Liabilities:     
Price risk management instruments (Note 10)     
Electricity$— $1 $238 $(25)$214 
Gas— 3 — — 3 
TOTAL LIABILITIES$— $4 $238 $(25)$217 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value. 
 Fair Value Measurements
 
At December 31, 2019
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$1,323 $— $— $— $1,323 
Nuclear decommissioning trusts
Short-term investments6 — — — 6 
Global equity securities2,086 — — — 2,086 
Fixed-income securities862 728 — — 1,590 
Assets measured at NAV— — — — 21 
Total nuclear decommissioning trusts (2)
2,954 728 — — 3,703 
Price risk management instruments (Note 10)    
Electricity— 2 161 (11)152 
Gas— 3 — 3 6 
Total price risk management instruments— 5 161 (8)158 
Rabbi trusts    
Fixed-income securities— 100 — — 100 
Life insurance contracts— 73 — — 73 
Total rabbi trusts— 173 — — 173 
Long-term disability trust    
Short-term investments10 — — — 10 
Assets measured at NAV— — — — 156 
Total long-term disability trust10 — — — 166 
TOTAL ASSETS$4,287 $906 $161 $(8)$5,523 
Liabilities:    
Price risk management instruments (Note 10)    
Electricity1 2 156 (13)146 
Gas— 2 — (1)1 
TOTAL LIABILITIES$1 $4 $156 $(14)$147 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2020 and 2019.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.
Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  The Utility utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  See Note 10 above.
 Fair Value at   
(in millions)At December 31, 2020Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$153 $74 Market approachCRR auction prices
$ (320.25) - 320.25 / 0.30
Power purchase agreements$13 $164 Discounted cash flowForward prices
$ 12.56 - 148.30 / 35.52
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
 Fair Value at   
(in millions)At December 31, 2019Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$140 $44 Market approachCRR auction prices
$ (20.20) - 20.20 / 0.28
Power purchase agreements$21 $112 Discounted cash flowForward prices
$ 11.77 - 59.38 / 33.62
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2020 and 2019, respectively:
 Price Risk Management Instruments
(in millions)20202019
Asset (liability) balance as of January 1$5 $95 
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)
(77)(90)
Asset (liability) balance as of December 31$(72)$5 
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2020 and 2019, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
 At December 31,
 20202019
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount(1)
Level 2 Fair Value(1)(2)
Debt (Note 5)    
PG&E Corporation
$1,901 $2,175 $— $— 
Utility29,664 32,632 1,500 1,500 
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5.
(2) The fair value of the Utility pre-petition debt was $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5.
Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:
(in millions)Amortized
Cost		Total
Unrealized
Gains		Total
Unrealized
Losses		Total Fair
Value
As of December 31, 2020    
Nuclear decommissioning trusts    
Short-term investments$27 $— $— $27 
Global equity securities543 1,881 (1)2,423 
Fixed-income securities1,610 152 (3)1,759 
Total (1)
$2,180 $2,033 $(4)$4,209 
As of December 31, 2019    
Nuclear decommissioning trusts    
Short-term investments$6 $— $— $6 
Global equity securities500 1,609 (2)2,107 
Fixed-income securities1,505 89 (4)1,590 
Total (1)
$2,011 $1,698 $(6)$3,703 
(1) Represents amounts before deducting $671 million and $530 million at December 31, 2020 and 2019, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2020
Less than 1 year$50 
1–5 years475 
5–10 years403 
More than 10 years831 
Total maturities of fixed-income securities$1,759 

The following table provides a summary of activity for the fixed-income and equity securities:
(in millions)202020192018
Proceeds from sales and maturities of nuclear decommissioning investments$1,518 $956 $1,412 
Gross realized gains on securities 159 69 54 
Gross realized losses on securities(41)(14)(24)
v3.20.4
EMPLOYEE BENEFIT PLANS
 12 Months Ended
Dec. 31, 2020
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract]  
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS
Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates.

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.
Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2020 and 2019:

Pension Plan
(in millions)20202019
Change in plan assets:
Fair value of plan assets at beginning of year$18,547 $15,312 
Actual return on plan assets2,736 3,713 
Company contributions343 328 
Benefits and expenses paid(867)(806)
Fair value of plan assets at end of year$20,759 $18,547 
Change in benefit obligation:
Benefit obligation at beginning of year$20,525 $17,407 
Service cost for benefits earned530 443 
Interest cost713 758 
Actuarial loss (1)
2,271 2,723 
Plan amendments— — 
Benefits and expenses paid(867)(806)
Benefit obligation at end of year (2)
$23,172 $20,525 
Funded Status:
Current liability$(3)$(14)
Noncurrent liability(2,410)(1,964)
Net liability at end of year
$(2,413)$(1,978)
(1) The actuarial losses for the years ended December 31, 2020 and 2019 were primarily due to a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was also driven by unfavorable changes in the demographic assumptions used to measure the projected benefit obligation.
(2) PG&E Corporation’s accumulated benefit obligation was $20.7 billion and $18.4 billion at December 31, 2020 and 2019, respectively.
Postretirement Benefits Other than Pensions
(in millions)20202019
Change in plan assets:
Fair value of plan assets at beginning of year$2,678 $2,258 
Actual return on plan assets379 474 
Company contributions26 29 
Plan participant contribution81 82 
Benefits and expenses paid(169)(165)
Fair value of plan assets at end of year$2,995 $2,678 
Change in benefit obligation:
Benefit obligation at beginning of year$1,832 $1,745 
Service cost for benefits earned61 56 
Interest cost63 76 
Actuarial (gain) loss (1)
(14)22 
Benefits and expenses paid(149)(150)
Federal subsidy on benefits paid3 2 
Plan participant contributions80 81 
Benefit obligation at end of year$1,876 $1,832 
Funded Status: (2)
Noncurrent asset$1,153 $879 
Noncurrent liability(34)(33)
Net asset at end of year$1,119 $846 
(1) The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was primarily due to a decrease in the discount rate used to measure the projected benefit obligation, offset by favorable changes in the demographic assumptions and the elimination of excise tax.
(2) At December 31, 2020 and 2019, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $377 million and $343 million as of December 31, 2020, and $337 million and $305 million as of December 31, 2019, respectively.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Net Periodic Benefit Cost

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.
Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan
(in millions)202020192018
Service cost for benefits earned (1)
$530 $443 $514 
Interest cost713 758 687 
Expected return on plan assets(1,044)(906)(1,021)
Amortization of prior service cost(6)(6)(6)
Amortization of net actuarial loss3 3 5 
Net periodic benefit cost196 292 179 
Less: transfer to regulatory account (2)
136 42 157 
Total expense recognized$332 $334 $336 
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions
(in millions)202020192018
Service cost for benefits earned (1)
$61 $56 $66 
Interest cost63 76 69 
Expected return on plan assets(138)(123)(130)
Amortization of prior service cost14 14 14 
Amortization of net actuarial loss(21)(3)(5)
Net periodic benefit cost$(21)$20 $14 
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above. 

Components of Accumulated Other Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).
Valuation Assumptions

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
 Pension PlanPBOP Plans
 December 31,December 31,
 202020192018202020192018
Discount rate2.77 %3.46 %4.35 %
2.67 - 2.80%
3.37 - 3.47%
4.29 - 4.37%
Rate of future compensation increases3.80 %3.90 %3.90 %N/AN/AN/A
Expected return on plan assets5.10 %5.70 %6.00 %
3.10 - 6.10%
3.50 - 6.60%
3.60 - 6.80%
Interest crediting rate for cash balance plan1.95 %2.11 %3.15 %N/AN/AN/A

The assumed health care cost trend rate as of December 31, 2020 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2028 and beyond. 

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 5.1% compares to a ten-year actual return of 9.6%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 835 Aa-grade non-callable bonds at December 31, 2020.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility.  In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global real estate investment trusts (“REITS”), global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios. 

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
 Pension PlanPBOP Plans
 202120202019202120202019
Global equity securities30 %30 %29 %36 %28 %33 %
Absolute return2 %2 %5 %1 %2 %3 %
Real assets8 %8 %8 %5 %8 %6 %
Fixed-income securities60 %60 %58 %58 %62 %58 %
Total100 %100 %100 %100 %100 %100 %

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2020 and 2019. 
 Fair Value Measurements
 At December 31,
 20202019
(in millions)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Pension Plan:        
Short-term investments$334 $408 $— $742 $613 $231 $— $844 
Global equity securities1,875 — — 1,875 1,650 — — 1,650 
Absolute Return1 1 — 2 — 1 — 1 
Real assets517 — — 517 548 1 — 549 
Fixed-income securities2,467 7,154 12 9,633 2,227 6,413 15 8,655 
Assets measured at NAV— — — 8,224 — — — 6,937 
Total$5,194 $7,563 $12 $20,993 $5,038 $6,646 $15 $18,636 
PBOP Plans:        
Short-term investments$37 $— $— $37 $37 $— $— $37 
Global equity securities173 — — 173 151 — — 151 
Real assets54 — — 54 58 — — 58 
Fixed-income securities481 715 1 1,197 193 875 1 1,069 
Assets measured at NAV— — — 1,549 — — — 1,373 
Total$745 $715 $1 $3,010 $439 $875 $1 $2,688 
Total plan assets at fair value   $24,003    $21,324 

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $249 million and other net liabilities of $99 million at December 31, 2020 and 2019, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. 

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.
Short-Term Investments

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

Global Equity securities

The global equity category includes investments in common stock and equity-index futures.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

Real Assets

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. 

Fixed-Income securities

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2020 and 2019.
Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2020 and 2019:
(in millions)
For the year ended December 31, 2020
Fixed-Income
Balance at beginning of year$15 
Actual return on plan assets:
Relating to assets still held at the reporting date2 
Relating to assets sold during the period(3)
Purchases, issuances, sales, and settlements:
Purchases11 
Settlements(13)
Balance at end of year$12 
  
(in millions)
For the year ended December 31, 2019
Fixed-Income
Balance at beginning of year$8 
Actual return on plan assets:
  Relating to assets still held at the reporting date— 
Relating to assets sold during the period— 
Purchases, issuances, sales, and settlements:
Purchases11 
Settlements(4)
Balance at end of year$15 

There were no material transfers out of Level 3 in 2020 and 2019.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $343 million to the pension benefit plans and $26 million to the other benefit plans in 2020.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2020.  The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $15 million to the pension plan and other postretirement benefit plans, respectively, for 2021. 

Benefits Payments and Receipts

As of December 31, 2020, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
(in millions)Pension
Plan		PBOP
Plans		Federal
Subsidy
2021831 85 (6)
2022913 89 (6)
2023948 92 (6)
2024980 93 (7)
20251,009 95 (7)
Thereafter in the succeeding five years5,375 471 (41)
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $119 million, $109 million, and $105 million in 2020, 2019, and 2018, respectively. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
v3.20.4
RELATED PARTY AGREEMENTS AND TRANSACTIONS
 12 Months Ended
Dec. 31, 2020
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)202020192018
Utility revenues from:   
Administrative services provided to PG&E Corporation$3 $4 $4 
Utility expenses from:
Administrative services received from PG&E Corporation$108 $107 $94 
Utility employee benefit due to PG&E Corporation34 42 76 
At December 31, 2020 and 2019, the Utility had receivables of $35 million and $60 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $46 million and $118 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.
v3.20.4
WILDFIRE-RELATED CONTINGENCIES
 12 Months Ended
Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]  
WILDFIRE-RELATED CONTINGENCIES WILDFIRE-RELATED CONTINGENCIESPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
2015 Butte Fire

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire.
2018 Camp Fire and 2017 Northern California Wildfires Background

According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire.

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims were satisfied and discharged in accordance with the Plan, as described below.
Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date

Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.
On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.” On January 15, 2021, the Utility paid approximately $758 million of the $1.35 billion, pursuant to the Tax Benefits Payment Agreement.

On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees were extinguished in the third quarter of 2020.

On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims (as defined below) was satisfied, released and discharged in the third quarter of 2020.
Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”).

The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”).

These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date.
Restructuring Support Agreement with Holders of Subrogation Claims

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date.
Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also included (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation and the Utility and the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan was made on the Effective Date.
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

The Utility has submitted electric incident reports to the CPUC indicating that:

•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;

•various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time;

•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;
•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and

•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.

On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.”

Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant.

PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.)

In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Accordingly, PG&E Corporation and the Utility recorded a charge for potential losses in connection with the 2019 Kincade fire in the amount of $625 million for the year ended December 31, 2020 (before available insurance).

The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.
The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages.

The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete.

As of February 24, 2021, PG&E Corporation and the Utility are aware of 22 complaints on behalf of approximately 504 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. The petition requests that the cases be coordinated in Sonoma County Superior Court. On December 18, 2020, certain plaintiffs filed a brief in support of PG&E Corporation’s and the Utility’s petition. On December 21, 2020, January 4, 2021 and January 27, 2021, certain plaintiffs filed briefs that supported coordination but requested that the cases be coordinated in San Francisco County Superior Court. On February 2, 2021, pursuant to authorization from the California Judicial Council, a judge of the Sonoma County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for April 2, 2021.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation or the Utility were found to have been negligent.
2020 Zogg Fire

According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management.

On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that:

•wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time;

•according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area;

•the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes;

•on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and

•Cal Fire has not issued a determination as to the cause.

The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the 2020 Zogg fire. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties.

Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire and accordingly recorded a pre-tax charge in the amount of $275 million for the quarter ending December 31, 2020 (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.

The aggregate liability of $275 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $275 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal, state, county and local government entities or agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable.
PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $275 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties.

The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $867.5 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for $219 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $275 million probable loss estimate less an initial self-insured retention of $60 million, plus $4 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

As of February 24, 2021, PG&E Corporation and the Utility are aware of six complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent.
Loss Recoveries

PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Insurance
Insurance Coverage

PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million.

In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, 2020, PG&E Corporation and the Utility had prepaid insurance of $536 million, reflected in Other current assets on the Consolidated Balance Sheets.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter will be required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage.

The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)
Insurance Receivable

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2020, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $219 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance for the 2015 Butte fire and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
Insurance Receivable (in millions)2020 Zogg fire2019 Kincade fire2018 Camp fire2017 Northern California wildfires2015 Butte fireTotal
Balance at December 31, 2019
$— $— $1,380 $808 $50 $2,238 
Accrued insurance recoveries219 430 — — — 649 
Reimbursements— — (1,380)(783)(50)(2,213)
Balance at December 31, 2020
$219 $430 $— $25 $— $674 
Regulatory Recovery

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.

On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or five percent of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust.

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On November 12, 2020, the Trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene.
On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al. (now captioned Trotter v. PG&E Corp., et al.), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al. (now captioned Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. On November 5, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. On February 24, 2021, the Fire Victim Trust filed an amended complaint, alleging two causes of action for breach of fiduciary duty against certain former officers and directors. The first cause of action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires, and the second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire. PG&E Corporation and the Utility are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 7, 2021.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al. (now captioned Trotter v. Meserve, et al.), was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan.
The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action Litigation
Wildfire-Related Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively.  The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

On February 22, 2019, a third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court.
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 26, 2020. No hearing date has been set.
On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviated mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion.

On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility filed their objection to the Renewed 7023 Motion on October 29, 2020. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline set by the Bankruptcy Court as part of the oral decision to resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion, PG&E Corporation and the Utility filed a revised proposed order, which the Bankruptcy Court entered the same day. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion.
De-energization Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action.

On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter.

On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement.

The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.
Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors’ and officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases.
District Attorneys’ Offices Investigations

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.

Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022.

On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund.

On January 15, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a Trustee and a Claims Administrator. The Court continued the hearing to August 20, 2021 for a further update.

Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above.

The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information.
Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.
SEC Investigation

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.
Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.
AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics (described above). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.

As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan.

For additional information on the Wildfire Fund, see Note 3 above.
OTHER CONTINGENCIES AND COMMITMENTSPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  See “Purchase Commitments” below.  PG&E Corporation and the Utility have financial commitments described in “Other Commitments” below.  PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
Enforcement Matters

U.S. District Court Matters and Probation

In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
CPUC and FERC Matters
Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire

On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.

As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval.
Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.

(in millions)
Description(1)
ExpenseCapitalTotal
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)$236 $— $236 
Transmission Safety Inspections and Repairs Expense (TO)(2)
433 — 433 
Vegetation Management Support Costs (FHPMA)36 — 36 
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)82 66 148 
2018 Camp Fire CEMA Expense (CEMA)435 — 435 
2018 Camp Fire CEMA Capital for Restoration (CEMA)— 253 253 
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)— 84 84 
Total$1,222 $403 $1,625 
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
(2) Transmission amounts are under the FERC’s regulatory authority.

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025.

On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020.

The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan.

As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMA as of December 31, 2020 and intends to record the remaining charges of $46 million in 2021.

On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition.
Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for TO18, TO19, and TO20, respectively.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which the Utility requested rehearing could also impact the revenues recorded for the TO19 and TO20 periods.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18.

The Utility is unable to predict the timing or outcome of the FERC’s decisions in the TO18 proceeding.
Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $144 million and $116 million at December 31, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at December 31, 2020. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code.
On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that the plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”

On April 6, 2020, the plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020.

On June 8, 2020, the plaintiff filed its opening brief with the District Court. The Utility filed its opposition brief on July 6, 2020. The plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. On October 20, 2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing.

The Utility is unable to determine the timing and outcome of this proceeding.
GT&S Capital Expenditures 2011-2014

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case.  The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.

On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.

The Utility is unable to determine the timing and outcome of this proceeding.
CZU Lightning Complex Fire Notices of Violation

Several governmental entities have raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules, the California Coastal Commission alleging violations of the Coastal Act related to unpermitted development in the coastal zone, the Central Coast Regional Water Quality Control Board alleging unpermitted discharge to waters, and the Santa Cruz County Board of Supervisors adopting a resolution to file a complaint with the CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats, and the management of wood debris. The Coastal Commission issued a Notice of Violation letter to the Utility on November 20, 2020, the Central Coast Regional Water Quality Control Board issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued five Notices of Violation through February 8, 2021, and Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.
Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)December 31, 2020December 31, 2019
Topock natural gas compressor station$303 $362 
Hinkley natural gas compressor station132 138 
Former manufactured gas plant sites owned by the Utility or third parties (1)
659 568 
Utility-owned generation facilities (other than fossil fuel-fired),
  other facilities, and third-party disposal sites (2)
111 101 
Fossil fuel-fired generation facilities and sites (3)
96 106 
Total environmental remediation liability$1,301 $1,275 
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws.  The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At December 31, 2020, the Utility expected to recover $986 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $460 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  
NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.8 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.8 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Diablo Canyon Outages

Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator are expected to occur during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions.

If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC.

Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery.
The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC.
Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		OtherNatural
Gas		Nuclear
Fuel		Total
2021$2,270 $582 $65 $466 $64 $3,447 
20222,042 511 62 191 54 2,860 
20231,997 223 61 158 49 2,488 
20241,972 72 61 151 47 2,303 
20251,962 70 61 151 — 2,244 
Thereafter21,335 281 41 184 — 21,841 
Total purchase commitments$31,578 $1,739 $351 $1,301 $214 $35,183 

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2020, renewable energy contracts expire at various dates between 2021 and 2043.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2020, these power purchase agreements expire at various dates between 2021 and 2033.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2020, QF contracts in operation expire at various dates between 2021 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity amounted to $2.9 billion in 2020, $3.0 billion in 2019, and $3.1 billion in 2018.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2021 and 2026.  In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.8 billion in 2020, $0.9 billion in 2019, and $0.6 billion in 2018.
Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2021 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $111 million in 2020, $74 million in 2019, and $73 million in 2018.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2021 and 2052.  At December 31, 2020, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2021$40 
202230 
202346 
202465 
202560 
Thereafter2,924 
Total minimum lease payments$3,165 

Payments for other commitments amounted to $45 million in 2020, $48 million in 2019, and $43 million in 2018.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively.  The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively.

Oakland Headquarters Lease

On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.

Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.
The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023.

In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO.

At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS
 12 Months Ended
Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]  
OTHER CONTINGENCIES AND COMMITMENTS WILDFIRE-RELATED CONTINGENCIESPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
2015 Butte Fire

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire.
2018 Camp Fire and 2017 Northern California Wildfires Background

According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of November 15, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 18,804 structures resulting from the 2018 Camp fire.

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims were satisfied and discharged in accordance with the Plan, as described below.
Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date

Pre-petition wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.
On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Additional Units Issuance, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the Fire Victim Trust Assignment Agreement. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.” On January 15, 2021, the Utility paid approximately $758 million of the $1.35 billion, pursuant to the Tax Benefits Payment Agreement.

On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees were extinguished in the third quarter of 2020.

On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims (as defined below) was satisfied, released and discharged in the third quarter of 2020.
Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”).

The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”).

These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date.
Restructuring Support Agreement with Holders of Subrogation Claims

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date.
Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also included (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation and the Utility and the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan was made on the Effective Date.
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

The Utility has submitted electric incident reports to the CPUC indicating that:

•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;

•various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time;

•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;
•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and

•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.

On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.”

Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant.

PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.)

In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. Accordingly, PG&E Corporation and the Utility recorded a charge for potential losses in connection with the 2019 Kincade fire in the amount of $625 million for the year ended December 31, 2020 (before available insurance).

The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.
The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of potential damages.

The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete.

As of February 24, 2021, PG&E Corporation and the Utility are aware of 22 complaints on behalf of approximately 504 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. The petition requests that the cases be coordinated in Sonoma County Superior Court. On December 18, 2020, certain plaintiffs filed a brief in support of PG&E Corporation’s and the Utility’s petition. On December 21, 2020, January 4, 2021 and January 27, 2021, certain plaintiffs filed briefs that supported coordination but requested that the cases be coordinated in San Francisco County Superior Court. On February 2, 2021, pursuant to authorization from the California Judicial Council, a judge of the Sonoma County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for April 2, 2021.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation or the Utility were found to have been negligent.
2020 Zogg Fire

According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management.

On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that:

•wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time;

•according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area;

•the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes;

•on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and

•Cal Fire has not issued a determination as to the cause.

The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the 2020 Zogg fire. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties.

Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire and accordingly recorded a pre-tax charge in the amount of $275 million for the quarter ending December 31, 2020 (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above.

The aggregate liability of $275 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $275 million estimate does not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal, state, county and local government entities or agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable.
PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $275 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties.

The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $867.5 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of December 31, 2020, the Utility has recorded an insurance receivable for $219 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $275 million probable loss estimate less an initial self-insured retention of $60 million, plus $4 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

As of February 24, 2021, PG&E Corporation and the Utility are aware of six complaints on behalf of approximately 240 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court.

In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability, including if PG&E Corporation and the Utility were found to have been negligent.
Loss Recoveries

PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Insurance
Insurance Coverage

PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million.

In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million. At December 31, 2020, PG&E Corporation and the Utility had prepaid insurance of $536 million, reflected in Other current assets on the Consolidated Balance Sheets.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter will be required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage.

The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)
Insurance Receivable

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2020, PG&E Corporation and the Utility recorded $430 million for probable insurance recoveries in connection with the 2019 Kincade fire, and $219 million for probable insurance recoveries in connection with the 2020 Zogg fire. PG&E Corporation and the Utility have recovered all of the insurance for the 2015 Butte fire and the 2018 Camp fire. PG&E Corporation and the Utility have recovered all of the insurance except for $25 million for the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
Insurance Receivable (in millions)2020 Zogg fire2019 Kincade fire2018 Camp fire2017 Northern California wildfires2015 Butte fireTotal
Balance at December 31, 2019
$— $— $1,380 $808 $50 $2,238 
Accrued insurance recoveries219 430 — — — 649 
Reimbursements— — (1,380)(783)(50)(2,213)
Balance at December 31, 2020
$219 $430 $— $25 $— $674 
Regulatory Recovery

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain; therefore, the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.

On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or five percent of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $592 million payment due to the Fire Victim Trust.

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.
Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018 and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay was subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On November 12, 2020, the Trustee for the Fire Victim Trust filed a motion to intervene to substitute as the plaintiff in the matter. A case management conference is currently scheduled for March 18, 2021, at which time the court will also hear the motion to intervene.
On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al. (now captioned Trotter v. PG&E Corp., et al.), was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of the Chapter 11 Cases, as discussed below. On December 14, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It named as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and named PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al. (now captioned Trotter v. Earley, et al.), was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. On January 7, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al. (now captioned Trotter v. Chew, et al.), was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. On November 5, 2020, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. On February 24, 2021, the Fire Victim Trust filed an amended complaint, alleging two causes of action for breach of fiduciary duty against certain former officers and directors. The first cause of action alleges breaches of fiduciary duty in connection with the 2017 Northern California wildfires, and the second cause of action alleges breaches of fiduciary duty in connection with the 2018 Camp fire. PG&E Corporation and the Utility are no longer named as nominal defendants. A case management conference is currently set for March 18, 2021.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. A case management conference is currently set for July 7, 2021.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al. (now captioned Trotter v. Meserve, et al.), was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant. On January 8, 2021, the court entered a stipulation and order to substitute the Fire Victim Trust as the plaintiff. A case management conference is currently set for April 15, 2021.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date of the Plan.
The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these claims to the Fire Victim Trust, any recovery based on these claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.Securities Class Action Litigation
Wildfire-Related Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively.  The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings were automatically stayed as to PG&E Corporation and the Utility pursuant to section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

On February 22, 2019, a third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court.
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to, among others, the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into separate categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims, which comprises two separate classes under the Plan, consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E Corporation and the Utility filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 26, 2020. No hearing date has been set.
On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviated mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties filed objections to the Securities Claims Procedures Motion.

On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation and the Utility filed their objection to the Renewed 7023 Motion on October 29, 2020. On December 4, 2020, the Bankruptcy Court issued an oral decision approving PG&E Corporation’s and the Utility’s Securities Claims Procedures Motion and denying PERA’s Renewed 7023 Motion. On January 25, 2021, following a timeline set by the Bankruptcy Court as part of the oral decision to resolve any outstanding non-substantive objections to PG&E Corporation’s and the Utility’s proposed order granting the Securities Claims Procedures Motion, PG&E Corporation and the Utility filed a revised proposed order, which the Bankruptcy Court entered the same day. On January 26, 2021, the Bankruptcy Court entered a written order denying the Renewed 7023 Motion.
De-energization Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40, 361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action.

On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. In October 2020, the parties reached a settlement agreement in principle, and on October 29, 2020, filed a joint notice of settlement, informing the District Court that they have agreed in principle to settle the matter.

On February 16, 2021, plaintiffs filed a motion for preliminary approval of the settlement with the District Court, and the District Court issued an order terminating as moot the pending motion to dismiss, without prejudice. Pursuant to the settlement stipulation, subject to certain conditions: (1) PG&E Corporation will pay $10 million into an interest-bearing escrow account within 14 days after the District Court’s preliminary approval of the settlement; and (2) plaintiffs and the Settlement Class (as defined in the stipulation of settlement) will release the Released Persons (as defined the stipulation of settlement, including PG&E Corporation and the Utility, and each of their officers, directors, as well as the current and former officers named in both the original and amended complaints) from all claims that have been or could have been asserted by or on behalf of PG&E Corporation shareholders that relate to (a) allegations that were asserted or could have been asserted in either of the complaints in Vataj, and (b) investments in PG&E Corporation’s stock during the relevant period specified in the stipulated settlement.

The settlement is subject to the District Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing is currently scheduled for March 11, 2021. The final approval hearing is not yet scheduled. If the District Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.
Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors’ and officers’ insurance coverage to reduce their exposure to such indemnification obligations. PG&E Corporation and the Utility have provided notice to their insurance carriers of the claims asserted in the wildfire-related securities class actions and derivative litigation, and are in communication with the carriers regarding the applicability of the directors and officers insurance policies to those matters. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. PG&E Corporation’s and the Utility’s indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases.
District Attorneys’ Offices Investigations

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.

Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte District Attorney’s consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022.

On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund.

On January 15, 2021, the Butte County Superior Court held a brief hearing on the status of restitution, which involves distribution of funds from the Fire Victim Trust, which was established under the Company’s Plan of Reorganization in Bankruptcy Court and is managed by a Trustee and a Claims Administrator. The Court continued the hearing to August 20, 2021 for a further update.

Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. On February 24, 2021, the Sonoma County District Attorney’s Office sent a search warrant to the Utility through its counsel in connection with the investigation. The Utility expects to produce documents and respond to other requests for information in connection with the investigation and the search warrant. For more information see “2019 Kincade Fire” above.

The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information.
Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.
SEC Investigation

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.
Wildfire Fund under AB 1054

On July 12, 2019, the California governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

Electric utility companies that draw from the Wildfire Fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.7 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on Wildfire Fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved WMP, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. On July 29, 2020, the Utility submitted its application for a new safety certification. On January 14, 2021, the WSD approved the Utility’s 2020 application and issued the Utility’s 2020 Safety Certification pursuant to the requirements of AB 1054. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. The 2020 Safety Certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. On January 26, 2021, TURN filed with the CPUC a request for review of WSD’s issuance of the safety certification.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three IOU companies and (iii) $300 million in annual contributions paid by California’s three IOU companies for at least a 10 year period. The contributions from the IOU companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three IOU companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.
AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three IOU companies on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the IOU companies in accordance with their Wildfire Fund allocation metrics (described above). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

On the Effective Date, having satisfied the conditions for the Utility’s initial participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund.

As of the Effective Date, the Wildfire Fund became available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan.

For additional information on the Wildfire Fund, see Note 3 above.
OTHER CONTINGENCIES AND COMMITMENTSPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  See “Purchase Commitments” below.  PG&E Corporation and the Utility have financial commitments described in “Other Commitments” below.  PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.
Enforcement Matters

U.S. District Court Matters and Probation

In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
CPUC and FERC Matters
Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire

On June 27, 2019, the CPUC issued the Wildfires OII to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.

As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s OSA, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval.
Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. While, as a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates, the Utility has committed not to seek rate recovery for the Tubbs fire except through securitization. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.

(in millions)
Description(1)
ExpenseCapitalTotal
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)$236 $— $236 
Transmission Safety Inspections and Repairs Expense (TO)(2)
433 — 433 
Vegetation Management Support Costs (FHPMA)36 — 36 
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)82 66 148 
2018 Camp Fire CEMA Expense (CEMA)435 — 435 
2018 Camp Fire CEMA Capital for Restoration (CEMA)— 253 253 
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)— 84 84 
Total$1,222 $403 $1,625 
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
(2) Transmission amounts are under the FERC’s regulatory authority.

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025.

On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020.

The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan.

As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $152 million primarily in WMPMA as of December 31, 2020 and intends to record the remaining charges of $46 million in 2021.

On June 8, 2020, two parties filed separate applications for rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. On December 3, 2020, the CPUC issued a decision denying the application for rehearing. On January 4, 2021, one party filed a petition for review of the CPUC decision with the California court of appeals. The Utility is unable to predict the timing and outcome of the petition.
Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, March 1, 2018, and May 1, 2019 for TO18, TO19, and TO20, respectively.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. On October 15, 2020, the FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning the FERC’s revised ROE methodology adopted in the FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs were filed December 14, 2020 and reply briefs were filed February 12, 2021. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility filed a request for rehearing of certain aspects of the order, which was denied by the FERC on December 17, 2020. The Utility filed a petition for review of the order on February 11, 2021, and a separate petition for review was jointly filed the same day by two other parties. The ultimate outcome of the items for which the Utility requested rehearing could also impact the revenues recorded for the TO19 and TO20 periods.

On September 21, 2018, the Utility filed an all-party settlement with the FERC, which was approved by the FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18.

The Utility is unable to predict the timing or outcome of the FERC’s decisions in the TO18 proceeding.
Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $144 million and $116 million at December 31, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at December 31, 2020. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.
PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code.
On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that the plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus the plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”

On April 6, 2020, the plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. The plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. The plaintiff filed a designation of the record and statement of the issues on April 20, 2020.

On June 8, 2020, the plaintiff filed its opening brief with the District Court. The Utility filed its opposition brief on July 6, 2020. The plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. On October 20, 2020, the District Court denied the plaintiff’s request for oral argument and stated that if it wants to hear oral argument, it will inform the parties and schedule a hearing.

The Utility is unable to determine the timing and outcome of this proceeding.
GT&S Capital Expenditures 2011-2014

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case.  The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.

On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. On January 20, 2021, the Utility provided supplemental testimony and supporting working papers addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.

The Utility is unable to determine the timing and outcome of this proceeding.
CZU Lightning Complex Fire Notices of Violation

Several governmental entities have raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire alleging violations of Public Resource Code sections related to timber harvest regulations and Forest Practice Rules, the California Coastal Commission alleging violations of the Coastal Act related to unpermitted development in the coastal zone, the Central Coast Regional Water Quality Control Board alleging unpermitted discharge to waters, and the Santa Cruz County Board of Supervisors adopting a resolution to file a complaint with the CPUC. The concerns include potential environmental impacts related to erosion and sedimentation from hazard tree removal and access road use, work in sensitive habitats, and the management of wood debris. The Coastal Commission issued a Notice of Violation letter to the Utility on November 20, 2020, the Central Coast Regional Water Quality Control Board issued a Notice of Violation letter on December 15, 2020, Cal Fire has issued five Notices of Violation through February 8, 2021, and Santa Cruz County filed a complaint with the CPUC on January 25, 2021. The Utility continues to work with all agencies, as well as Santa Cruz County, to resolve any outstanding issues.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. The Utility is unable to reasonably estimate the amount or range of potential penalties that could be incurred given the number of factors that can be considered in determining penalties. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows. Violations can result in penalties, remediation and other relief.
Environmental Remediation Contingencies

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)December 31, 2020December 31, 2019
Topock natural gas compressor station$303 $362 
Hinkley natural gas compressor station132 138 
Former manufactured gas plant sites owned by the Utility or third parties (1)
659 568 
Utility-owned generation facilities (other than fossil fuel-fired),
  other facilities, and third-party disposal sites (2)
111 101 
Fossil fuel-fired generation facilities and sites (3)
96 106 
Total environmental remediation liability$1,301 $1,275 
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws.  The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors the environmental requirements on an ongoing basis and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at December 31, 2020, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At December 31, 2020, the Utility expected to recover $986 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.
Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $216 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $138 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $460 million if the extent of contamination or necessary remediation at currently identified MGP sites is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $67 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $43 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.
Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL, a mutual insurer owned by utilities with nuclear facilities, and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  
NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.7 billion per non-nuclear incident for Diablo Canyon. For Humboldt Bay Unit 3, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. This coverage amount is shared by all NEIL members and applies to all terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL.

In addition to the nuclear insurance the Utility maintains through NEIL, the Utility also is a member of EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides an additional $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies.

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to approximately $13.8 billion. The Utility purchases the maximum available public liability insurance of $450 million for Diablo Canyon. The balance of the $13.8 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $275 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $41 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident. In addition, the Utility has approximately $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

Diablo Canyon Outages

Diablo Canyon Unit 2 has experienced four outages between July 2020 and February 24, 2021, each due or related to malfunctions within the main generator associated with excessive vibrations. Additional inspections and replacement of a redesigned component of the generator are expected to occur during Unit 2’s planned spring 2021 refueling outage. The affected component is part of the secondary system and does not involve a risk of release of radioactive material into the environment. The Utility is working with the vendor that supplied the affected component to understand the root cause and to develop appropriate corrective actions.

If additional shutdowns occur in the future, or if the planned refueling outage is extended due to the inspections and replacement of the affected component, the Utility may incur incremental costs or forgo additional power market revenues. The Utility will also be subject to a review of the reasonableness of its actions before the CPUC.

Diablo Canyon carries property damage and outage insurance issued by NEIL. The Utility has notified NEIL of its potential claims for loss recovery.
The Utility is unable to reasonably estimate the occurrence or length of future outages, the cost to repair the generator, the loss of power market revenues, or the results of a reasonableness review by the CPUC.
Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		OtherNatural
Gas		Nuclear
Fuel		Total
2021$2,270 $582 $65 $466 $64 $3,447 
20222,042 511 62 191 54 2,860 
20231,997 223 61 158 49 2,488 
20241,972 72 61 151 47 2,303 
20251,962 70 61 151 — 2,244 
Thereafter21,335 281 41 184 — 21,841 
Total purchase commitments$31,578 $1,739 $351 $1,301 $214 $35,183 

Third-Party Power Purchase Agreements

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2020, renewable energy contracts expire at various dates between 2021 and 2043.

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2020, these power purchase agreements expire at various dates between 2021 and 2033.

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2020, QF contracts in operation expire at various dates between 2021 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity amounted to $2.9 billion in 2020, $3.0 billion in 2019, and $3.1 billion in 2018.

Natural Gas Supply, Transportation, and Storage Commitments 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2021 and 2026.  In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.8 billion in 2020, $0.9 billion in 2019, and $0.6 billion in 2018.
Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2021 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $111 million in 2020, $74 million in 2019, and $73 million in 2018.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities and land leases, which expire at various dates between 2021 and 2052.  At December 31, 2020, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2021$40 
202230 
202346 
202465 
202560 
Thereafter2,924 
Total minimum lease payments$3,165 

Payments for other commitments amounted to $45 million in 2020, $48 million in 2019, and $43 million in 2018.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

One of these commitments is treated as a financing lease. At December 31, 2020 and 2019, net financing leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $7 million and $9 million including accumulated amortization of $11 million and $9 million, respectively.  The present value of the future minimum lease payments due under these agreements included $2 million and $2 million in Current Liabilities and $5 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, at December 31, 2020 and 2019, respectively.

Oakland Headquarters Lease

On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Lakeside Building by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.

Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the Lakeside Building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) and a lease security letter of credit in the amount of $75 million.

The term of the Lease will begin on or about March 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.
The Lease requires the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Lakeside Building to create a separate legal parcel that contains the Lakeside Building (the “Property”) that can be sold to the Utility. The Lease grants to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023.

In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO.

At December 31, 2020, the Lease Agreement had no impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.
v3.20.4
SUBSEQUENT EVENTS
 12 Months Ended
Dec. 31, 2020
Subsequent Events [Abstract]  
SUBSEQUENT EVENTS SUBSEQUENT EVENTS
Sale of Transmission Tower Wireless Licenses

On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers.

The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue.

In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million, subject to customary adjustments. SBA paid the Utility $954 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period, resulting in initial cash proceeds of $945 million. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement.

The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market potential additional attachment locations on approximately 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement.
v3.20.4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
 12 Months Ended
Dec. 31, 2020
Condensed Financial Information Disclosure [Abstract]  
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 Years Ended December 31,
(in millions, except per share amounts)202020192018
Administrative service revenue$127 $138 $90 
Operating expenses(103)(114)(91)
Interest income— 1 2 
Interest expense(149)(21)(15)
Other income (expense)13 10 (2)
Reorganization items, net(1,649)(26)— 
Equity in earnings of subsidiaries411 (7,622)(6,832)
Loss before income taxes(1,350)(7,634)(6,848)
Income tax provision (benefit)(46)8 3 
Net loss$(1,304)$(7,642)$(6,851)
Other Comprehensive Income (Loss)   
Pension and other postretirement benefit plans obligations (net of taxes of $7, $0, and $2, at respective dates)
$(17)$(1)$4 
Total other comprehensive income (loss)(17)(1)4 
Comprehensive Loss$(1,321)$(7,643)$(6,847)
Weighted Average Common Shares Outstanding, Basic1,257 528 517 
Weighted Average Common Shares Outstanding, Diluted1,257 528 513 
Net loss per common share, basic$(1.05)$(14.50)$(13.25)
Net loss per common share, diluted$(1.05)$(14.50)$(13.25)
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED BALANCE SHEETS
 Balance at December 31,
(in millions)20202019
ASSETS  
Current Assets  
Cash and cash equivalents$223 $448 
Advances to affiliates48 120 
Income taxes receivable12 12 
Other current assets13 11 
Total current assets296 591 
Noncurrent Assets  
Equipment2 2 
Accumulated depreciation(2)(2)
Net equipment— — 
Investments in subsidiaries25,244 5,102 
Other investments186 173 
Operating lease right of use asset3 6 
Deferred income taxes237 187 
Total noncurrent assets25,670 5,468 
Total Assets$25,966 $6,059 
LIABILITIES AND SHAREHOLDERS’ EQUITY  
Current Liabilities  
Long-term debt, classified as current28 — 
Accounts payable – other49 47 
Operating lease liabilities3 3 
Other current liabilities72 3 
Total current liabilities152 53 
Noncurrent Liabilities  
Debtor-in-possession financing4,624 — 
Operating lease liabilities— 3 
Other noncurrent liabilities191 58 
Total noncurrent liabilities4,815 61 
Liabilities Subject to Compromise— 810 
Common Shareholders’ Equity  
Common stock30,224 13,038 
Reinvested earnings(9,198)(7,893)
Accumulated other comprehensive income (loss)(27)(10)
Total common shareholders’ equity20,999 5,135 
Total Liabilities and Shareholders’ Equity$25,966 $6,059 
PG&E CORPORATION
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
 Year ended December 31,
 202020192018
Cash Flows from Operating Activities:   
Net loss$(1,304)$(7,642)$(6,851)
Adjustments to reconcile net income to net cash provided by operating activities:   
Stock-based compensation amortization28 43 78 
Equity in earnings of subsidiaries(412)7,622 6,833 
Deferred income taxes and tax credits-net(50)— (62)
Reorganization items, net (Note 2) 1,548 11 — 
Current income taxes receivable/payable— 6 9 
Liabilities subject to compromise12 28 — 
Other97 (62)41 
Net cash provided by (used in) operating activities
(81)6 48 
Cash Flows From Investing Activities:   
Investment in subsidiaries(12,986)— (45)
Net cash used in investing activities
(12,986)— (45)
Cash Flows From Financing Activities:   
Debtor-in-possession credit facility debt issuance costs— (16)— 
Bridge facility financing fees(40)— — 
Borrowings under revolving credit facility— — 425 
Repayments under revolving credit facility— — (125)
Net repayments of commercial paper— — (132)
Short-term debt financing— — 350 
Proceeds from issuance of long-term debt4,660 — — 
Repayment of long-term debt(664)— (350)
Common stock issued7,582 85 200 
Equity Units issued1,304 — — 
Net cash provided by financing activities12,842 69 368 
Net change in cash and cash equivalents(225)75 371 
Cash and cash equivalents at January 1448 373 2 
Cash and cash equivalents at December 31$223 $448 $373 
Supplemental disclosures of cash flow information   
Cash received (paid) for:   
Interest, net of amounts capitalized$(105)$(3)$(13)
Income taxes, net— — 10 
Supplemental disclosures of noncash investing and financing activities
Operating lease liabilities arising from obtaining ROU assets$— $9 $— 
Common stock issued in satisfaction of liabilities8,276 — — 
v3.20.4
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
 12 Months Ended
Dec. 31, 2020
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]  
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2020, 2019, and 2018
(in millions) Additions  
DescriptionBalance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:     
2020:     
      Allowance for uncollectible accounts (1)
$43 $138 $— $35 $146 
2019: 
      Allowance for uncollectible accounts (1)
$56 $— $— $13 $43 
2018: 
      Allowance for uncollectible accounts (1)
$64 $34 $— $42 $56 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2020, 2019, and 2018
(in millions) Additions  
DescriptionBalance at Beginning of PeriodCharged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:     
2020:     
      Allowance for uncollectible accounts (1)
$43 $138 $— $35 $146 
2019:
      Allowance for uncollectible accounts (1)
$56 $— $— $13 $43 
2018:
      Allowance for uncollectible accounts (1)
$64 $34 $— $42 $56 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 12 Months Ended
Dec. 31, 2020
Accounting Policies [Abstract]  
Basis of Presentation This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.
Use of Estimates and Assumptions The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.
Loss Contingencies
Loss Contingencies

A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.
Regulation and Regulated Operations
Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Revenue Recognition
Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which generally occur every three or four years.  The Utility's ability to recover revenue requirements authorized by the CPUC in these rate cases is independent or “decoupled” from the volume of the Utility's sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
Cash, Cash Equivalents and Restricted Cash
Cash, Cash Equivalents, and Restricted Cash

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.  As of December 31, 2020, the Utility also holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.
Allowance for Doubtful Accounts Receivable and Credit Losses
Allowance for Doubtful Accounts Receivable and Credit Losses

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectible customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

In addition, upon adopting ASU 2016-13, PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. See “Financial Instruments - Credit Losses” below for more information.
Inventories
Inventories

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Emission Allowances
Emission Allowances

The Utility purchases GHG emission allowances to satisfy its compliance obligations.  Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets.  Costs are carried at weighted-average and are recoverable through rates.
Property, Plant, And Equipment
Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
 Estimated UsefulBalance at December 31,
(in millions, except estimated useful lives)Lives (years)20202019
Electricity generating facilities (1)
5 to 75
$13,751 $13,189 
Electricity distribution facilities
10 to 70
37,675 35,237 
Electricity transmission facilities
15 to 75
15,556 14,281 
Natural gas distribution facilities
20 to 60
15,133 14,236 
Natural gas transmission and storage facilities
5 to 66
9,002 8,452 
Construction work in progress 2,757 2,675 
Other18 18 
Total property, plant, and equipment 93,892 88,088 
Accumulated depreciation (27,756)(26,453)
Net property, plant, and equipment
 $66,136 $61,635 
(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 15 below.)

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.76% in 2020, 3.80% in 2019, and 3.82% in 2018.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC AFUDCAFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.
Nuclear Decommissioning Obligation
Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The total nuclear decommissioning obligation accrued was $5.1 billion and $4.9 billion at December 31, 2020 and 2019, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion at December 31, 2020 and 2019.
Disallowance of Plant Costs Disallowance of Plant CostsPG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.
Nuclear Decommissioning Trusts
Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
Variable Interest Entities
Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.  

Consolidated VIE

The SPV is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program (as defined in Note 5 below), the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Consolidated Balance Sheets. The aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated.

The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2020 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2020, the SPV has $2.6 billion of net accounts receivable and has outstanding borrowings of $1.0 billion under the Receivables Securitization Program.

Non-Consolidated VIEs

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2020, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2020, it did not consolidate any of them.
Recognition of Lease Assets and Liabilities
Recognition of Lease Assets and Liabilities

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.
Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Consolidated Balance Sheets. Financing leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Consolidated Balance Sheets.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted
Recently Adopted Accounting Standards

Intangibles—Goodwill and Other

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the Consolidated Financial Statements and related disclosures.
Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses On Financial Instruments, which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. PG&E Corporation and the Utility adopted the ASU on January 1, 2020.

PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. As of December 31, 2020, expected credit losses of $150 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded at December 31, 2020, $76 million and $10 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation’s or the Utility’s Consolidated Financial Statements resulting from the adoption of this ASU.

Defined Benefit Plans

In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for defined benefit plans. PG&E Corporation and the Utility adopted the ASU as of December 31, 2020. The adoption of ASU 2018-14 resulted in elimination of the disclosures of (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year and (ii) the effects of a one-percentage-point change in assumed health care cost trend rates on the (1) aggregate of the service and interest cost components of net periodic benefit costs and (2) benefit obligation for postretirement health care benefits. Additionally, the adoption of this ASU resulted in new disclosures of (i) the weighted-average interest crediting rates for cash balance plans and (ii) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. These amendments have been applied on a retrospective basis to all periods presented. See Note 12 below for further discussion of PG&E Corporation’s and the Utility’s defined benefit pension plans.

Accounting Standards Issued But Not Yet Adopted

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. This ASU became effective for PG&E Corporation and the Utility on January 1, 2021 and will not have a material impact on the Consolidated Financial Statements and the related disclosures.
Debt

In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.
Earnings Per Share PG&E Corporation’s basic EPS is calculated by dividing the income (loss) available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Fair Value Measurement
PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

•Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

•Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
v3.20.4
BANKRUPTCY FILING (Tables)
 12 Months Ended
Dec. 31, 2020
Reorganizations [Abstract]  
Schedule Of Liabilities Subject To Compromise
Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified as of December 31, 2020 consist of the following:
(in millions)Utility
PG&E
Corporation (1)
December 31, 2019
PG&E
Corporation
Consolidated
Change in Estimated Allowed Claim 2020 (2)
Cash
Payment
Reclassified as of June 30, 2020 (3)
Utility
PG&E
Corporation (1)
December 31, 2020
PG&E
Corporation
Consolidated
Financing debt
$22,450 $666 $23,116 $351 $— $(23,467)$— $— $— 
Wildfire-related claims
25,548 — 25,548 18 (23)(25,543)— — — 
Trade creditors (4)
1,183 5 1,188 6 (14)(1,180)— — — 
Non-qualified benefit plan20 137 157 — — (157)— — — 
2001 bankruptcy disputed claims234 — 234 4 — (238)— — — 
Customer deposits & advances71 — 71 12 — (83)— — — 
Other230 2 232 59 — (291)— — — 
Total Liabilities Subject to Compromise$49,736 $810 $50,546 $450 $(37)$(50,959)$— $— $— 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims,” “customer deposits & advances,” and “other” line items which are mainly due to the adjustment to recorded liabilities.
(3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets.
(4) As of February 18, 2021, $5 million and $941 million has been repaid by PG&E Corporation and the Utility, respectively.
Schedule Of Debtor Reorganization Items Reorganization items, net for the year ended December 31, 2020 include the following:
Year Ended December 31, 2020
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$6 $— $6 
Legal and other (2)
318 1,651 1,969 
Interest and other(14)(2)(16)
Total reorganization items, net$310 $1,649 $1,959 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
(2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees.

Reorganization items, net from the Petition Date through December 31, 2019 include the following:
Petition Date Through December 31, 2019
(in millions)Utility
PG&E Corporation (1)
PG&E Corporation Consolidated
Debtor-in-possession financing costs$97 $17 $114 
Legal and other273 19 292 
Interest income(50)(10)(60)
Total reorganization items, net$320 $26 $346 
(1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)
 12 Months Ended
Dec. 31, 2020
Accounting Policies [Abstract]  
Summary of Revenues Disaggregated by Type of Customer
The following table presents the Utility’s revenues disaggregated by type of customer:
Year Ended
(in millions)20202019
Electric
Revenue from contracts with customers
   Residential$5,523 $4,847 
   Commercial4,722 4,756 
   Industrial1,530 1,493 
   Agricultural1,471 1,106 
   Public street and highway lighting69 67 
   Other (1)
(130)168 
      Total revenue from contracts with customers - electric13,185 12,437 
Regulatory balancing accounts (2)
673 303 
Total electric operating revenue$13,858 $12,740 
Natural gas
Revenue from contracts with customers
   Residential$2,517 $2,325 
   Commercial597 605 
   Transportation service only1,211 1,249 
   Other (1)
61 123 
      Total revenue from contracts with customers - gas4,386 4,302 
Regulatory balancing accounts (2)
225 87 
Total natural gas operating revenue4,611 4,389 
Total operating revenues$18,469 $17,129 
(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.
(2) These amounts represent revenues authorized to be billed or refunded to customers.
Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
 Estimated UsefulBalance at December 31,
(in millions, except estimated useful lives)Lives (years)20202019
Electricity generating facilities (1)
5 to 75
$13,751 $13,189 
Electricity distribution facilities
10 to 70
37,675 35,237 
Electricity transmission facilities
15 to 75
15,556 14,281 
Natural gas distribution facilities
20 to 60
15,133 14,236 
Natural gas transmission and storage facilities
5 to 66
9,002 8,452 
Construction work in progress 2,757 2,675 
Other18 18 
Total property, plant, and equipment 93,892 88,088 
Accumulated depreciation (27,756)(26,453)
Net property, plant, and equipment
 $66,136 $61,635 
(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 15 below.)
Schedule of Changes in Asset Retirement Obligations
The following table summarizes the changes in ARO liability during 2020 and 2019, including nuclear decommissioning obligations:
(in millions)20202019
ARO liability at beginning of year$5,854 $5,994 
Liabilities incurred in the current period268 — 
Revision in estimated cash flows53 (376)
Accretion265 274 
Liabilities settled(28)(38)
ARO liability at end of year$6,412 $5,854 
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2020 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits		Total
Beginning balance$(22)$17 $(5)
Other comprehensive income before reclassifications:
Unrecognized net actuarial gain (loss) (net of taxes of $162 and $66, respectively)
(417)170 (247)
Regulatory account transfer (net of taxes of $155 and $66, respectively)
400 (170)230 
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)
(4)10 6 
Amortization of net actuarial (gain) loss (net of taxes of $1 and $6, respectively) (1)
2 (15)(13)
Regulatory account transfer (net of taxes of $1 and $2, respectively) (1)
2 5 7 
Net current period other comprehensive loss(17)— (17)
Ending balance$(39)$17 $(22)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 12 below for additional details.) 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2019 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits		Total
Beginning balance$(21)$17 $(4)
Other comprehensive income before reclassifications:
Unrecognized net actuarial loss (net of taxes of $24 and $88, respectively)
61 227 288 
Regulatory account transfer (net of taxes of $24 and $88, respectively)
(62)(227)(289)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)
(4)10 6 
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)
2 (2)— 
Regulatory account transfer (net of taxes of $1 and $3, respectively) (1)
2 (8)(6)
Net current period other comprehensive loss(1)— (1)
Ending balance$(22)$17 $(5)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 12 below for additional details.)
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)20202019
Operating lease fixed cost$679 $686 
Operating lease variable cost1,852 1,778 
Total operating lease costs$2,531 $2,464 
Schedule of Future Expected Operating Lease Payments
At December 31, 2020, the Utility’s future expected operating lease payments were as follows:
(in millions)December 31, 2020
2021$624 
2022550 
2023257 
202498 
202591 
Thereafter513 
Total lease payments2,133 
Less imputed interest(397)
Total$1,736 
v3.20.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)
 12 Months Ended
Dec. 31, 2020
Regulated Operations [Abstract]  
Long-Term Regulatory Assets
Long-term regulatory assets are comprised of the following:
 Balance at December 31,Recovery
Period
(in millions)20202019
Pension benefits (1)
$2,245 $1,823 Indefinitely
Environmental compliance costs1,112 1,062 32 years
Utility retained generation (2)
181 228 6 years
Price risk management204 124 19 years
Unamortized loss, net of gain, on reacquired debt
49 63 23 years
Catastrophic event memorandum account (3)
842 656 
1 - 3 years
Wildfire expense memorandum account (4)
400 423 
1 - 3 years
Fire hazard prevention memorandum account (5)
137 259 
1 - 3 years
Fire risk mitigation memorandum account (6)
66 95 
1 - 3 years
Wildfire mitigation plan memorandum account (7)
390 558 
1 - 3 years
Deferred income taxes (8)
908 252 51 years
Insurance premium costs (9)
294 — 
1 - 4 years
Wildfire mitigation balancing account (10)
156 — 
1 - 3 years
General rate case memorandum accounts (11)
376 — 
1 - 2 years
Vegetation management balancing account (12)
592 — 
1 - 3 years
COVID-19 pandemic protection memorandum accounts (13)
84 — TBD years
Other942 523 Various
Total long-term regulatory assets$8,978 $6,066  
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. 
(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of December 31, 2020, $49 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval.
(4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval.
(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval.
(6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval.
(7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020. Recovery of WMPMA costs is subject to CPUC review and approval.
(8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively.
(10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through December 31, 2020. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval.
(11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through the date of the final 2020 GRC decision as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 17 months, beginning March 1, 2021.
(12) The 2020 GRC Decision authorized the Utility to modify the existing one-way VMBA Expense Balancing Account to a two-way balancing account to track the difference between actual and adopted expenses resulting from its routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval.
(13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of December 31, 2020, the Utility had recorded an aggregate under-collection of $76 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $8 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
Long-Term Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following:
 Balance at December 31,
(in millions)20202019
Cost of removal obligations (1)
$6,905 $6,456 
Recoveries in excess of AROs (2)
458 393 
Public purpose programs (3)
948 817 
Employee benefit plans (4)
995 750 
Other1,118 854 
Total long-term regulatory liabilities
$10,424 $9,270 
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 11 below.)
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans.
Current Regulatory Balancing Accounts Receivable
Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable
Balance at December 31,
(in millions)20202019
Electric transmission$— $9 
Gas distribution and transmission102 363 
Energy procurement413 901 
Public purpose programs292 209 
Fire hazard prevention memorandum account121 — 
Fire risk mitigation memorandum account
33 — 
Wildfire mitigation plan memorandum account161 — 
Wildfire mitigation balancing account27 — 
General rate case memorandum accounts313 — 
Vegetation management balancing account115 — 
Insurance premium costs135 — 
Other289 632 
Total regulatory balancing accounts receivable$2,001 $2,114 
Current Regulatory Balancing Accounts Payable
Payable
Balance at December 31,
(in millions)20202019
Electric distribution$55 $31 
Electric transmission267 119 
Gas distribution and transmission76 45 
Energy procurement158 649 
Public purpose programs410 559 
Other279 394 
Total regulatory balancing accounts payable$1,245 $1,797 
v3.20.4
DEBT (Tables)
 12 Months Ended
Dec. 31, 2020
Debt Disclosure [Abstract]  
Schedule of Line of Credit Facilities
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at December 31, 2020:
(in millions)Termination
Date		Facility LimitBorrowings OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJuly 2023$3,500 
(1)
$605 $1,020 $1,875 
Utility term loan credit facility
Various(2)
3,000 3,000 — — 
Utility receivables securitization programOctober 20221,000 1,000 — — 
PG&E Corporation revolving credit facilityJuly 2023500 — — 500 
Total credit facilities$8,000 $4,605 $1,020 $2,375 
(1) Includes a $1.5 billion letter of credit sublimit.
(2) This includes a $1.5 billion term loan credit facility with a maturity date of June 30, 2021 and a $1.5 billion term loan credit facility with a maturity date of January 1, 2022.
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 (3)
December 31, 2020December 31, 2019
Treatment under Plan on the Effective Date (1)
Pre-Petition Debt (2)
PG&E Corporation
Borrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022
variable rate (4)
$— $300 
Repaid in cash (14)
Other borrowings
Term Loan - Stated Maturity: 2020
 variable rate (5)
— 350 
Repaid in cash (14)
Total PG&E Corporation Pre-Petition Long-Term Debt— 650 
Utility
Senior Notes - Stated Maturity:
2020 through 2022
2.45% to 4.25%
— 1,750 
Exchanged (15)
2023 through 2028
2.95% to 4.65%
— 5,025 
Reinstated (16)
2034 through 2040
5.40% to 6.35%
— 5,700 
Exchanged (17)
2041 through 2042
3.75% to 4.50%
— 1,000 
Reinstated (16)
20435.13%— 500 
Exchanged (17)
2043 through 2047
3.95% to 4.75%
— 3,550 
Reinstated (16)
Total Pre-Petition Senior Notes— 17,525 
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026
1.75%— 100 
Repaid in cash (14)
Series 2009 A-B, due 2026
variable rate (6)
— 149 
Exchanged (18)
Series 1996 C, E, F, 1997 B due 2026
variable rate (7)
— 614 
Exchanged (18)
Total Pre-Petition Pollution Control Bonds— 863 
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022
 variable rate (8)
— 2,888 
Exchanged (18)
Other borrowings:
Term Loan - Stated Maturity: 2019
 variable rate (9)
— 250 
Exchanged (18)
Total Borrowings under Pre-Petition Credit Facility— 3,138 
Total Utility Pre-Petition Debt— 21,526 
Total PG&E Corporation Consolidated Pre-Petition Debt$— $22,176 
New Long-Term Debt
PG&E Corporation
Term Loan - Stated Maturity: 2025
variable rate (10)
$2,709 $— 
Senior Secured Notes due 20285.00%1,000 — 
Senior Secured Notes due 20305.25%1,000 — 
Unamortized discount, net of premium and debt issuance costs(85)— 
Total PG&E Corporation New Long-Term Debt4,624 — 
Utility
Pre-Petition Senior Notes Reinstated as First Mortgage Bonds - Stated Maturity:
2023 through 2028
2.95% to 4.65%
5,025 — 
2041 through 2042
3.75% to 4.50%
1,000 — 
2043 through 2047
3.95% to 4.75%
3,550 — 
Unamortized discount, net of premium and debt issuance costs— — 
Total Utility Reinstated New Long-Term Debt9,575 — 
Pre-Petition Debt Exchanged for First Mortgage Bonds - Stated Maturity:
20253.45%875 — 
20263.15%1,951 — 
20283.75%875 — 
20304.55%3,100 — 
20404.50%1,951 — 
20504.95%3,100 — 
Unamortized discount, net of premium and debt issuance costs(98)— 
Total Utility Exchanged New Long-Term Debt11,754 — 
New First Mortgage Bonds - Stated Maturity:
2022
variable rate (11)
500 — 
20221.75%2,500 — 
20272.10%1,000 — 
20312.50%2,000 — 
20403.30%1,000 — 
20503.50%1,925 — 
Unamortized discount, net of premium and debt issuance costs(84)— 
Total Utility New First Mortgage Bonds8,841 — 
Credit Facilities - Stated Maturity: 2022
Receivables securitization program
variable rate (12)
1,000 — 
18-month Term Loan
variable rate (13)
1,500 — 
Unamortized discount, net of premium and debt issuance costs(6)— 
Total Utility New Long-Term Debt32,664 — 
Total PG&E Corporation Consolidated New Long-Term Debt$37,288 $— 
(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2.
(2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court.
(3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and 2020, respectively.
(4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%.
(5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%.
(6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%.
(7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%.
(8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%.
(9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%.
(10) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 5.50%.
(11) At December 31, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.70%.
(12) At December 31, 2020, the contractual LIBOR-based interest rate on the receivables securitization program was 1.57%.
(13) At December 31, 2020, the contractual LIBOR-based interest rate on the term loan was 2.44%.
(14) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020.
(15) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(16) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above.
(17) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
(18) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.
Schedule of Contractual Repayment Schedule
PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2020 are reflected in the table below:
(in millions,       
except interest rates)20212022202320242025ThereafterTotal
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, 20205.50 %5.50 %5.50 %5.50 %5.50 %— %5.50 %
Variable rate obligations$28 $28 $28 $28 $2,625 $— $2,737 
Utility
Average fixed interest rate— %1.75 %3.83 %3.60 %3.47 %3.87 %3.66 %
Fixed rate obligations$— $2,500 $1,175 $800 $1,475 $23,902 $29,852 
Variable interest rate as of December 31, 2020— %
various (1)
— %— %— %— %
various (1)
Variable rate obligations
$— $3,000 $— $— $— $— $3,000 
Total consolidated debt$28 $5,528 $1,203 $828 $4,100 $25,902 $37,589 
(1) At December 31, 2020, the average interest rates for the Receivables Securitization Program, the first mortgage bonds due 2022 and the 18-month term loan were 1.57%, 1.70% and 2.44% respectively.
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)
 12 Months Ended
Dec. 31, 2020
Common Stock And Share-Based Compensation [Abstract]  
Schedule of Compensation Expense for Share-based Incentive Awards
The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2020:
(in millions)
202020192018
Stock Options$3 $7 $10 
Restricted stock units15 21 43 
Performance shares17 22 36 
Total compensation expense (pre-tax)$35 $50 $89 
Total compensation expense (after-tax)$25 $35 $63 
Summary of Significant Assumptions Used for Shares Granted The significant assumptions used for shares granted in 2019 were:
2019
Expected stock price volatility57.00 %
Expected annual dividend payment— %
Risk-free interest rate
1.51% to 1.52%
Expected life (years)4.5
Summary of Stock Option Activity
The following table summarizes stock option activity for PG&E Corporation and the Utility for 2020:
Number of
Stock Options		Weighted Average Grant-
Date Fair Value		Weighted Average Remaining Contractual TermAggregate Intrinsic Value
Outstanding at January 14,281,403 $5.98 $— 
Granted (1)
20,065 3.87 — 
Exercised— — — 
Forfeited or expired(2,080,221)3.87 — 
Outstanding at December 312,221,247 7.45 5.33 years— 
Vested or expected to vest at December 312,215,076 7.43 5.31 years— 
Exercisable at December 311,840,893 $6.86 4.93 years$— 
(1) Represents additional payout of existing stock option grants.
Schedule of Restricted Stock Units
The following table summarizes restricted stock unit activity for 2020:
Number of
Restricted Stock Units		Weighted Average Grant-
Date Fair Value
Nonvested at January 11,040,835 $44.06 
Granted1,007,782 9.25 
Vested(944,090)33.14 
Forfeited(214,174)15.75 
Nonvested at December 31890,353 $23.05 
Schedule of Performance Shares
The following table summarizes activity for performance shares in 2020:
Number of
Performance Shares		Weighted Average Grant-
Date Fair Value
Nonvested at January 1688,423 $36.92 
Granted7,951,541 9.62 
Vested(132,526)41.27 
Forfeited (1)
(1,218,656)24.38 
Nonvested at December 317,288,782 $9.16 
(1) Includes performance shares that expired with zero value as performance targets were not met.
v3.20.4
EARNINGS PER SHARE (Tables)
 12 Months Ended
Dec. 31, 2020
Earnings Per Share [Abstract]  
Earnings Per Share The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2020, 2019, and 2018.
 Year Ended December 31,
(in millions, except per share amounts)202020192018
Loss attributable to common shareholders$(1,318)$(7,656)$(6,851)
Weighted average common shares outstanding, basic1,257 528 517 
Add incremental shares from assumed conversions:
Employee share-based compensation
— — — 
Equity Units— — — 
Weighted average common share outstanding, diluted1,257 528 517 
Total Loss per common share, diluted$(1.05)$(14.50)$(13.25)
v3.20.4
INCOME TAXES (Tables)
 12 Months Ended
Dec. 31, 2020
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 CorporationUtility
 
Year Ended December 31,
(in millions)202020192018202020192018
Current:      
Federal$(26)$1 $(5)$(26)$4 $5 
State(34)101 (8)(34)94 (7)
Deferred:
Federal258 (2,361)(2,264)290 (2,363)(2,278)
State171 (1,136)(1,009)185 (1,137)(1,009)
Tax credits(7)(5)(6)(7)(5)(6)
Income tax provision (benefit)
$362 $(3,400)$(3,292)$408 $(3,407)$(3,295)
Schedule of Deferred Tax Assets and Liabilities
The following tables describe net deferred income tax assets and liabilities:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)2020201920202019
Deferred income tax assets:    
Tax carryforwards$7,641 $1,390 $7,529 $1,308 
Compensation187 151 109 92 
Wildfire-related claims (1)
544 6,520 544 6,520 
Operating lease liability
489 642 488 640 
Other (2)
212 112 219 121 
Total deferred income tax assets$9,073 $8,815 $8,889 $8,681 
Deferred income tax liabilities:    
Property related basis differences8,311 7,984 8,300 7,973 
Regulatory balancing accounts763 381 763 381 
Debt financing costs526 — 526 — 
Operating lease right of use asset489 642 488 640 
Income tax regulatory asset(3)
254 71 254 71 
Other (4)
128 57 128 58 
Total deferred income tax liabilities$10,471 $9,135 $10,459 $9,123 
Total net deferred income tax liabilities$1,398 $320 $1,570 $442 
(1) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to various wildfires that have occurred on PG&E Corporation’s and the Utility’s service territory over the past several years.
(2) Amounts include benefits, environmental reserve, and customer advances for construction. 
(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.
(4) Amount primarily includes an environmental reserve.
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 CorporationUtility
 Year Ended December 31,
 202020192018202020192018
Federal statutory income tax rate21.0 %21.0 %21.0 %21.0 %21.0 %21.0 %
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(15.3)7.5 7.9 19.1 7.5 7.9 
Effect of regulatory treatment of fixed asset differences (2)
39.0 2.8 3.6 (44.9)2.8 3.6 
Tax credits1.5 0.1 0.1 (1.7)0.1 0.1 
Bankruptcy and emergence (3)
(82.5)— — 54.1 — — 
Other, net (4)
(2.1)(0.6)(0.1)2.2 (0.5)— 
Effective tax rate(38.4)%30.8 %32.5 %49.8 %30.9 %32.6 %
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  In 2020, 2019, and 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.
(3) The Utility includes an adjustment for the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust. PG&E Corporation includes the same adjustment as the Utility and a permanent non-deductible equity backstop premium expense. This combined with a pre-tax loss and a pre-tax income for PG&E Corporation and the Utility, respectively, accounts for the remaining difference.
(4) These amounts primarily represent the impact of tax audit settlements and non-tax deductible costs in 2020 and 2019.
Schedule of Change in Unrecognized Tax Benefits
The following table reconciles the changes in unrecognized tax benefits:
 PG&E CorporationUtility
(in millions)202020192018202020192018
Balance at beginning of year$420 $377 $349 $420 $377 $349 
Reductions for tax position taken during a prior year(43)(1)(27)(43)(1)(27)
Additions for tax position taken during the current year60 44 55 60 44 55 
Settlements— — — — — — 
Expiration of statute— — — — — — 
Balance at end of year
$437 $420 $377 $437 $420 $377 
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, 2020Expiration
Year
Federal:  
Net operating loss carryforward - Pre-2018$3,600 2031 - 2036
Net operating loss carryforward - Post-201724,887 N/A
Tax credit carryforward134 2029 - 2040
State:
Net operating loss carryforward$25,364 2039 - 2040
Tax credit carryforward100 Various
v3.20.4
DERIVATIVES (Tables)
 12 Months Ended
Dec. 31, 2020
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 December 31,
Underlying ProductInstruments20202019
Natural Gas (1) (MMBtus (2))
Forwards, Futures and Swaps146,642,863 131,896,159 
 Options14,140,000 14,720,000 
Electricity (Megawatt-hours)Forwards, Futures and Swaps9,435,830 18,675,852 
Options— — 
 
Congestion Revenue Rights (3)
266,091,470 308,467,999 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Outstanding Derivative Balances
At December 31, 2020, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$33 $— $115 $148 
Other noncurrent assets – other136 — — 136 
Current liabilities – other(38)— 15 (23)
Noncurrent liabilities – other(204)— 10 (194)
Total commodity risk$(73)$— $140 $67 

At December 31, 2019, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$36 $(6)$4 $34 
Other noncurrent assets – other130 (6)— 124 
Current liabilities – other(31)6 2 (23)
Noncurrent liabilities – other(130)6 — (124)
Total commodity risk$5 $— $6 $11 
v3.20.4
FAIR VALUE MEASUREMENTS (Tables)
 12 Months Ended
Dec. 31, 2020
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, 2020
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$470 $— $— $— $470 
Nuclear decommissioning trusts
Short-term investments27 — — — 27 
Global equity securities2,398 — — — 2,398 
Fixed-income securities924 835 — — 1,759 
Assets measured at NAV— — — — 25 
Total nuclear decommissioning trusts (2)
3,349 835 — — 4,209 
Price risk management instruments (Note 10)     
Electricity— 2 166 2 170 
Gas— 1 — 113 114 
Total price risk management instruments— 3 166 115 284 
Rabbi trusts     
Fixed-income securities— 106 — — 106 
Life insurance contracts— 79 — — 79 
Total rabbi trusts— 185 — — 185 
Long-term disability trust     
Short-term investments9 — — — 9 
Assets measured at NAV— — — — 158 
Total long-term disability trust9 — — — 167 
TOTAL ASSETS$3,828 $1,023 $166 $115 $5,315 
Liabilities:     
Price risk management instruments (Note 10)     
Electricity$— $1 $238 $(25)$214 
Gas— 3 — — 3 
TOTAL LIABILITIES$— $4 $238 $(25)$217 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value. 
 Fair Value Measurements
 
At December 31, 2019
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$1,323 $— $— $— $1,323 
Nuclear decommissioning trusts
Short-term investments6 — — — 6 
Global equity securities2,086 — — — 2,086 
Fixed-income securities862 728 — — 1,590 
Assets measured at NAV— — — — 21 
Total nuclear decommissioning trusts (2)
2,954 728 — — 3,703 
Price risk management instruments (Note 10)    
Electricity— 2 161 (11)152 
Gas— 3 — 3 6 
Total price risk management instruments— 5 161 (8)158 
Rabbi trusts    
Fixed-income securities— 100 — — 100 
Life insurance contracts— 73 — — 73 
Total rabbi trusts— 173 — — 173 
Long-term disability trust    
Short-term investments10 — — — 10 
Assets measured at NAV— — — — 156 
Total long-term disability trust10 — — — 166 
TOTAL ASSETS$4,287 $906 $161 $(8)$5,523 
Liabilities:    
Price risk management instruments (Note 10)    
Electricity1 2 156 (13)146 
Gas— 2 — (1)1 
TOTAL LIABILITIES$1 $4 $156 $(14)$147 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.
(2) Represents amount before deducting $530 million, primarily related to deferred taxes on appreciation of investment value.
Uncertainty Analysis
 Fair Value at   
(in millions)At December 31, 2020Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$153 $74 Market approachCRR auction prices
$ (320.25) - 320.25 / 0.30
Power purchase agreements$13 $164 Discounted cash flowForward prices
$ 12.56 - 148.30 / 35.52
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
 Fair Value at   
(in millions)At December 31, 2019Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$140 $44 Market approachCRR auction prices
$ (20.20) - 20.20 / 0.28
Power purchase agreements$21 $112 Discounted cash flowForward prices
$ 11.77 - 59.38 / 33.62
(1) Represents price per megawatt-hour.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2020 and 2019, respectively:
 Price Risk Management Instruments
(in millions)20202019
Asset (liability) balance as of January 1$5 $95 
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)
(77)(90)
Asset (liability) balance as of December 31$(72)$5 
(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
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,
 20202019
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount(1)
Level 2 Fair Value(1)(2)
Debt (Note 5)    
PG&E Corporation
$1,901 $2,175 $— $— 
Utility29,664 32,632 1,500 1,500 
(1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5.
(2) The fair value of the Utility pre-petition debt was $17.9 billion as of December 31, 2019. For more information, see Note 2 and Note 5.
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
Cost		Total
Unrealized
Gains		Total
Unrealized
Losses		Total Fair
Value
As of December 31, 2020    
Nuclear decommissioning trusts    
Short-term investments$27 $— $— $27 
Global equity securities543 1,881 (1)2,423 
Fixed-income securities1,610 152 (3)1,759 
Total (1)
$2,180 $2,033 $(4)$4,209 
As of December 31, 2019    
Nuclear decommissioning trusts    
Short-term investments$6 $— $— $6 
Global equity securities500 1,609 (2)2,107 
Fixed-income securities1,505 89 (4)1,590 
Total (1)
$2,011 $1,698 $(6)$3,703 
(1) Represents amounts before deducting $671 million and $530 million at December 31, 2020 and 2019, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Long Term Debt Repayments
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2020
Less than 1 year$50 
1–5 years475 
5–10 years403 
More than 10 years831 
Total maturities of fixed-income securities$1,759 
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)202020192018
Proceeds from sales and maturities of nuclear decommissioning investments$1,518 $956 $1,412 
Gross realized gains on securities 159 69 54 
Gross realized losses on securities(41)(14)(24)
v3.20.4
EMPLOYEE BENEFIT PLANS (Tables)
 12 Months Ended
Dec. 31, 2020
Employee Benefit and Share-based Payment Arrangement, Noncash Expense [Abstract]  
Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2020 and 2019:

Pension Plan
(in millions)20202019
Change in plan assets:
Fair value of plan assets at beginning of year$18,547 $15,312 
Actual return on plan assets2,736 3,713 
Company contributions343 328 
Benefits and expenses paid(867)(806)
Fair value of plan assets at end of year$20,759 $18,547 
Change in benefit obligation:
Benefit obligation at beginning of year$20,525 $17,407 
Service cost for benefits earned530 443 
Interest cost713 758 
Actuarial loss (1)
2,271 2,723 
Plan amendments— — 
Benefits and expenses paid(867)(806)
Benefit obligation at end of year (2)
$23,172 $20,525 
Funded Status:
Current liability$(3)$(14)
Noncurrent liability(2,410)(1,964)
Net liability at end of year
$(2,413)$(1,978)
(1) The actuarial losses for the years ended December 31, 2020 and 2019 were primarily due to a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was also driven by unfavorable changes in the demographic assumptions used to measure the projected benefit obligation.
(2) PG&E Corporation’s accumulated benefit obligation was $20.7 billion and $18.4 billion at December 31, 2020 and 2019, respectively.
Postretirement Benefits Other than Pensions
(in millions)20202019
Change in plan assets:
Fair value of plan assets at beginning of year$2,678 $2,258 
Actual return on plan assets379 474 
Company contributions26 29 
Plan participant contribution81 82 
Benefits and expenses paid(169)(165)
Fair value of plan assets at end of year$2,995 $2,678 
Change in benefit obligation:
Benefit obligation at beginning of year$1,832 $1,745 
Service cost for benefits earned61 56 
Interest cost63 76 
Actuarial (gain) loss (1)
(14)22 
Benefits and expenses paid(149)(150)
Federal subsidy on benefits paid3 2 
Plan participant contributions80 81 
Benefit obligation at end of year$1,876 $1,832 
Funded Status: (2)
Noncurrent asset$1,153 $879 
Noncurrent liability(34)(33)
Net asset at end of year$1,119 $846 
(1) The actuarial gain for the year ended December 31, 2020 was primarily due to favorable changes in the demographic and medical cost assumptions, offset by a decrease in the discount rate used to measure the projected benefit obligation. The actuarial loss for the year ended December 31, 2019 was primarily due to a decrease in the discount rate used to measure the projected benefit obligation, offset by favorable changes in the demographic assumptions and the elimination of excise tax.
(2) At December 31, 2020 and 2019, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $377 million and $343 million as of December 31, 2020, and $337 million and $305 million as of December 31, 2019, respectively.
Components of Net Periodic Benefit Cost
Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan
(in millions)202020192018
Service cost for benefits earned (1)
$530 $443 $514 
Interest cost713 758 687 
Expected return on plan assets(1,044)(906)(1,021)
Amortization of prior service cost(6)(6)(6)
Amortization of net actuarial loss3 3 5 
Net periodic benefit cost196 292 179 
Less: transfer to regulatory account (2)
136 42 157 
Total expense recognized$332 $334 $336 
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions
(in millions)202020192018
Service cost for benefits earned (1)
$61 $56 $66 
Interest cost63 76 69 
Expected return on plan assets(138)(123)(130)
Amortization of prior service cost14 14 14 
Amortization of net actuarial loss(21)(3)(5)
Net periodic benefit cost$(21)$20 $14 
(1) A portion of service costs are capitalized pursuant to ASU 2017-07.
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 PlanPBOP Plans
 December 31,December 31,
 202020192018202020192018
Discount rate2.77 %3.46 %4.35 %
2.67 - 2.80%
3.37 - 3.47%
4.29 - 4.37%
Rate of future compensation increases3.80 %3.90 %3.90 %N/AN/AN/A
Expected return on plan assets5.10 %5.70 %6.00 %
3.10 - 6.10%
3.50 - 6.60%
3.60 - 6.80%
Interest crediting rate for cash balance plan1.95 %2.11 %3.15 %N/AN/AN/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 PlanPBOP Plans
 202120202019202120202019
Global equity securities30 %30 %29 %36 %28 %33 %
Absolute return2 %2 %5 %1 %2 %3 %
Real assets8 %8 %8 %5 %8 %6 %
Fixed-income securities60 %60 %58 %58 %62 %58 %
Total100 %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, 2020 and 2019. 
 Fair Value Measurements
 At December 31,
 20202019
(in millions)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Pension Plan:        
Short-term investments$334 $408 $— $742 $613 $231 $— $844 
Global equity securities1,875 — — 1,875 1,650 — — 1,650 
Absolute Return1 1 — 2 — 1 — 1 
Real assets517 — — 517 548 1 — 549 
Fixed-income securities2,467 7,154 12 9,633 2,227 6,413 15 8,655 
Assets measured at NAV— — — 8,224 — — — 6,937 
Total$5,194 $7,563 $12 $20,993 $5,038 $6,646 $15 $18,636 
PBOP Plans:        
Short-term investments$37 $— $— $37 $37 $— $— $37 
Global equity securities173 — — 173 151 — — 151 
Real assets54 — — 54 58 — — 58 
Fixed-income securities481 715 1 1,197 193 875 1 1,069 
Assets measured at NAV— — — 1,549 — — — 1,373 
Total$745 $715 $1 $3,010 $439 $875 $1 $2,688 
Total plan assets at fair value   $24,003    $21,324 
Schedule of Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2020 and 2019:
(in millions)
For the year ended December 31, 2020
Fixed-Income
Balance at beginning of year$15 
Actual return on plan assets:
Relating to assets still held at the reporting date2 
Relating to assets sold during the period(3)
Purchases, issuances, sales, and settlements:
Purchases11 
Settlements(13)
Balance at end of year$12 
  
(in millions)
For the year ended December 31, 2019
Fixed-Income
Balance at beginning of year$8 
Actual return on plan assets:
  Relating to assets still held at the reporting date— 
Relating to assets sold during the period— 
Purchases, issuances, sales, and settlements:
Purchases11 
Settlements(4)
Balance at end of year$15 
Schedule of Estimated Benefits Expected to be Paid
As of December 31, 2020, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
(in millions)Pension
Plan		PBOP
Plans		Federal
Subsidy
2021831 85 (6)
2022913 89 (6)
2023948 92 (6)
2024980 93 (7)
20251,009 95 (7)
Thereafter in the succeeding five years5,375 471 (41)
v3.20.4
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables)
 12 Months Ended
Dec. 31, 2020
Related Party Transactions [Abstract]  
Schedule of Significant Related Party Transactions
The Utility’s significant related party transactions were:
 Year Ended December 31, 
(in millions)202020192018
Utility revenues from:   
Administrative services provided to PG&E Corporation$3 $4 $4 
Utility expenses from:
Administrative services received from PG&E Corporation$108 $107 $94 
Utility employee benefit due to PG&E Corporation34 42 76 
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Tables)
 12 Months Ended
Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]  
Summary of Wildfire-Related Claims
The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:
Insurance Receivable (in millions)2020 Zogg fire2019 Kincade fire2018 Camp fire2017 Northern California wildfires2015 Butte fireTotal
Balance at December 31, 2019
$— $— $1,380 $808 $50 $2,238 
Accrued insurance recoveries219 430 — — — 649 
Reimbursements— — (1,380)(783)(50)(2,213)
Balance at December 31, 2020
$219 $430 $— $25 $— $674 
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Tables)
 12 Months Ended
Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Expense and Capital Expenditures The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through December 31, 2020.
(in millions)
Description(1)
ExpenseCapitalTotal
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)$236 $— $236 
Transmission Safety Inspections and Repairs Expense (TO)(2)
433 — 433 
Vegetation Management Support Costs (FHPMA)36 — 36 
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)82 66 148 
2018 Camp Fire CEMA Expense (CEMA)435 — 435 
2018 Camp Fire CEMA Capital for Restoration (CEMA)— 253 253 
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)— 84 84 
Total$1,222 $403 $1,625 
(1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
(2) Transmission amounts are under the FERC’s regulatory authority.
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, 2020December 31, 2019
Topock natural gas compressor station$303 $362 
Hinkley natural gas compressor station132 138 
Former manufactured gas plant sites owned by the Utility or third parties (1)
659 568 
Utility-owned generation facilities (other than fossil fuel-fired),
  other facilities, and third-party disposal sites (2)
111 101 
Fossil fuel-fired generation facilities and sites (3)
96 106 
Total environmental remediation liability$1,301 $1,275 
(1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor.
(2) Primarily driven by Geothermal landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.
Schedule of Undiscounted Future Expected Power Purchase Agreement Payments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2020:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		OtherNatural
Gas		Nuclear
Fuel		Total
2021$2,270 $582 $65 $466 $64 $3,447 
20222,042 511 62 191 54 2,860 
20231,997 223 61 158 49 2,488 
20241,972 72 61 151 47 2,303 
20251,962 70 61 151 — 2,244 
Thereafter21,335 281 41 184 — 21,841 
Total purchase commitments$31,578 $1,739 $351 $1,301 $214 $35,183 
Schedule of other commitments At December 31, 2020, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2021$40 
202230 
202346 
202465 
202560 
Thereafter2,924 
Total minimum lease payments$3,165 
v3.20.4
ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details)
 12 Months Ended
Dec. 31, 2020
numberOfSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Number of operating segments (segment) 1
v3.20.4
BANKRUPTCY FILING (Plan of Reorganization and Restructuring Support Agreements) (Details) - USD ($)
 1 Months Ended 12 Months Ended
Jul. 01, 2020
Jun. 25, 2020
Sep. 22, 2019
Jul. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Jan. 15, 2021
Aug. 03, 2020
Jun. 12, 2020
Debt Instrument [Line Items]                    
Subrogation claims, professional fees     $ 55,000,000              
Proceeds from issuance or sale of equity $ 9,000,000,000.0 $ 3,970,000,000   $ 9,000,000,000.0 $ 1,304,000,000 $ 0 $ 0      
Plan of reorganization, tax benefits payment agreement $ 1,350,000,000                  
Transfer of shares to Fire Victim Trust (in shares) 477,000,000.0                  
Transfer of shares to Fire Victim Trust, additional (in shares)                 748,415  
TCC claims settlement, amount $ 11,000,000,000.0   $ 11,000,000,000.0              
Subsequent Event                    
Debt Instrument [Line Items]                    
Payment of plan of reorganization, tax benefits payment agreement               $ 758,000,000    
Settling Public Entities                    
Debt Instrument [Line Items]                    
Litigation payment 1,000,000,000.0                  
Litigation, segregated reimbursement fund 10,000,000                  
Minimum                    
Debt Instrument [Line Items]                    
Plan of reorganization, tax benefits payment agreement 650,000,000                  
Fire Victim Trust                    
Debt Instrument [Line Items]                    
Cash contribution by company $ 5,400,000,000                  
Percentage of common stock owned, Fire Victim Trust if common issues additional shares 22.19%                 22.19%
Litigation payment, fund, cash $ 5,400,000,000                  
Transfer of shares to Fire Victim Trust (in shares) 477,000,000                  
Transfer of shares to Fire Victim Trust, additional (in shares)                 748,415  
Subrogation Wildfire Trust                    
Debt Instrument [Line Items]                    
Subrogation claims, professional fees $ 52,000,000                  
Litigation payment, fund, cash 11,000,000,000.0                  
Litigation payment, funded 100,000,000                  
New PG&E Corporation Debt                    
Debt Instrument [Line Items]                    
Issuance 4,750,000,000                  
PG&E Corporation                    
Debt Instrument [Line Items]                    
Proceeds from issuance or sale of equity         1,304,000,000 0 $ 0      
PG&E Corporation | Pre-Petition Debt                    
Debt Instrument [Line Items]                    
Issuance 9,575,000,000                  
PG&E Corporation | New Utility Debt                    
Debt Instrument [Line Items]                    
Issuance 23,775,000,000                  
PG&E Corporation | New Utility Long-Term Bonds                    
Debt Instrument [Line Items]                    
Issuance $ 6,200,000,000                  
PG&E Corporation | First Mortgage Bonds Due 2030                    
Debt Instrument [Line Items]                    
Stated interest rate 4.55%                  
PG&E Corporation | First Mortgage Bonds Due 2050                    
Debt Instrument [Line Items]                    
Stated interest rate 4.95%                  
PG&E Corporation | New Utility Short-Term Bonds                    
Debt Instrument [Line Items]                    
Issuance $ 1,750,000,000                  
PG&E Corporation | First Mortgage Bonds Due 2025                    
Debt Instrument [Line Items]                    
Stated interest rate 3.45%                  
PG&E Corporation | First Mortgage Bonds Due 2028                    
Debt Instrument [Line Items]                    
Stated interest rate 3.75%                  
PG&E Corporation | New Utility Funded Debt Exchange Notes                    
Debt Instrument [Line Items]                    
Issuance $ 3,900,000,000                  
PG&E Corporation | First Mortgage Bonds, Exchange Stated Maturity 2025                    
Debt Instrument [Line Items]                    
Stated interest rate 3.15%                  
PG&E Corporation | First Mortgage Bonds, Exchange Stated Maturity 2040                    
Debt Instrument [Line Items]                    
Stated interest rate 4.50%                  
PG&E Corporation | New Debt Securities or Bank Debt                    
Debt Instrument [Line Items]                    
Issuance $ 11,925,000,000                  
Expected repayment 6,000,000,000.0                  
Pacific Gas & Electric Co (Utility)                    
Debt Instrument [Line Items]                    
Subrogation claims, professional fees         $ 53,000,000          
Plan of reorganization, future tax benefits payment agreement $ 1,350,000,000                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due October 2020                    
Debt Instrument [Line Items]                    
Stated interest rate 3.50%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due May 2021                    
Debt Instrument [Line Items]                    
Stated interest rate 4.25%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due September 2021                    
Debt Instrument [Line Items]                    
Stated interest rate 3.25%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due August 2020                    
Debt Instrument [Line Items]                    
Stated interest rate 2.45%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due 2034                    
Debt Instrument [Line Items]                    
Stated interest rate 6.05%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due March 2037                    
Debt Instrument [Line Items]                    
Stated interest rate 5.80%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due February 2038                    
Debt Instrument [Line Items]                    
Stated interest rate 6.35%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due March 2039                    
Debt Instrument [Line Items]                    
Stated interest rate 6.25%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due January 2040                    
Debt Instrument [Line Items]                    
Stated interest rate 5.40%                  
Pacific Gas & Electric Co (Utility) | Pre-petition Senior Notes, Due November 2043                    
Debt Instrument [Line Items]                    
Stated interest rate 5.125%                  
Pacific Gas & Electric Co (Utility) | Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026                    
Debt Instrument [Line Items]                    
Stated interest rate         0.0175%          
Pollution control bonds $ 100,000,000       $ 0 $ 100,000,000        
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2030                    
Debt Instrument [Line Items]                    
Stated interest rate 4.55%                  
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2050                    
Debt Instrument [Line Items]                    
Stated interest rate 4.95%                  
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2025                    
Debt Instrument [Line Items]                    
Stated interest rate 3.45%                  
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds Due 2028                    
Debt Instrument [Line Items]                    
Stated interest rate 3.75%                  
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Exchange Stated Maturity 2025                    
Debt Instrument [Line Items]                    
Stated interest rate         3.45%          
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Exchange Stated Maturity 2040                    
Debt Instrument [Line Items]                    
Stated interest rate         4.50%          
v3.20.4
BANKRUPTCY FILING (Equity Financing) (Details) - USD ($)
$ / shares in Units, shares in Millions
 1 Months Ended 12 Months Ended
Jul. 01, 2020
Jun. 25, 2020
Jul. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Sep. 30, 2020
Aug. 03, 2020
Jun. 30, 2020
Jun. 19, 2020
Mar. 06, 2020
Debt Instrument [Line Items]                      
Equity Units issued $ 9,000,000,000.0 $ 3,970,000,000 $ 9,000,000,000.0 $ 1,304,000,000 $ 0 $ 0          
Equity backstop commitments, shares (in shares) 119.0                    
Equity backstop commitments, value $ 12,000,000,000.0                    
Backstop commitment premium, expense                 $ 1,100,000,000    
Share price (in dollar per share) $ 9.03               $ 8.87    
Additional backstop commitment premium, expense             $ 19,000,000   $ 444,000,000    
Professional legal fees       34,000,000              
Professional non-legal fees       19,000,000              
Professional fees       49,000,000              
Settlement price (in dollars per share)                   $ 9.50  
Additional forward stock purchase agreement, expense             $ 8,000,000        
Backstop Parties                      
Debt Instrument [Line Items]                      
Debt commitment letters, required equity funding                     $ 12,000,000,000.0
Forward stock purchase agreement, common stock issues, pro rata (in shares)   50.0                  
Offerings                      
Debt Instrument [Line Items]                      
Equity Units issued       5,750,000,000              
Option Amount                      
Debt Instrument [Line Items]                      
Equity Units issued   $ 523,000,000                  
Common Stock Offering                      
Debt Instrument [Line Items]                      
Option to purchase additional stock, delivered (in shares)   42.3           42.3      
PG&E Corporation                      
Debt Instrument [Line Items]                      
Equity Units issued       $ 1,304,000,000 $ 0 $ 0          
Forward stock purchase, redemption amount               $ 120,500,000      
v3.20.4
BANKRUPTCY FILING (Schedule of Liabilities Subject to Compromise) (Details) - USD ($)
$ in Millions
 6 Months Ended 12 Months Ended
Jun. 30, 2020
Dec. 31, 2020
Feb. 18, 2021
Dec. 31, 2019
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, beginning balance $ 23,116.0 $ 23,116.0    
Wildfire-related claims, beginning balance 25,548.0 25,548.0    
Trade creditors, beginning balance 1,188.0 1,188.0    
Non-qualified benefit plan, beginning balance 157.0 157.0    
2001 bankruptcy disputed claims, beginning balance 234.0 234.0    
Customer deposits & advances, beginning balance 71.0 71.0    
Other, beginning balance 232.0 232.0    
Liabilities Subject to Compromise, beginning balance 50,546.0 50,546.0    
Financing debt, ending balance   0.0    
Wildfire-related claims, ending balance   0.0    
Trade creditors, ending balance   0.0    
Non-qualified benefit plan, ending balance   0.0    
2001 bankruptcy disputed claims, ending balance   0.0    
Customer deposits & advances, ending balance   0.0    
Other, ending balance   0.0    
Liabilities Subject to Compromise, ending balance   0.0    
Accounts payable - other   580.0   $ 566.0
Disputed claims and customer refunds   242.0   0.0
Interest payable   498.0   4.0
Short-term borrowings   3,547.0   0.0
Long-term debt, classified as current   28.0   0.0
Other   2,256.0   1,254.0
Other non-current liabilities   3,848.0   2,573.0
Pension and other postretirement benefits   2,444.0   1,884.0
Accounts payable - trade creditors   2,402.0   1,954.0
Wildfire-related claims   2,250.0   0.0
Change in Estimated Allowed Claim        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, change   351.0    
Wildfire-related claims, change   18.0    
Trade creditors, change   6.0    
Non-qualified benefit plan, change   0.0    
2011 bankruptcy disputed claims, change   4.0    
Customer deposits & advances, change   12.0    
Other, change   59.0    
Liabilities Subject to Compromise, change   450.0    
Cash Payment        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, change   0.0    
Wildfire-related claims, change   (23.0)    
Trade creditors, change   (14.0)    
Non-qualified benefit plan, change   0.0    
2011 bankruptcy disputed claims, change   0.0    
Customer deposits & advances, change   0.0    
Other, change   0.0    
Liabilities Subject to Compromise, change   (37.0)    
Reclassified        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, change (23,467.0)      
Wildfire-related claims, change (25,543.0)      
Trade creditors, change (1,180.0)      
Non-qualified benefit plan, change (157.0)      
2011 bankruptcy disputed claims, change (238.0)      
Customer deposits & advances, change (83.0)      
Other, change (291.0)      
Liabilities Subject to Compromise, change (50,959.0)      
Accounts payable - other 8.6      
Disputed claims and customer refunds 237.6      
Interest payable 1,347.4      
Debt financial instrument 21,425.7      
Short-term borrowings 300.0      
Long-term debt, classified as current 450.0      
Other 301.0      
Other non-current liabilities 97.9      
Pension and other postretirement benefits 121.3      
Accounts payable - trade creditors 1,126.9      
Wildfire-related claims 25,542.7      
Pacific Gas & Electric Co (Utility)        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, beginning balance 22,450.0 22,450.0    
Wildfire-related claims, beginning balance 25,548.0 25,548.0    
Trade creditors, beginning balance 1,183.0 1,183.0    
Non-qualified benefit plan, beginning balance 20.0 20.0    
2001 bankruptcy disputed claims, beginning balance 234.0 234.0    
Customer deposits & advances, beginning balance 71.0 71.0    
Other, beginning balance 230.0 230.0    
Liabilities Subject to Compromise, beginning balance 49,736.0 49,736.0    
Financing debt, ending balance   0.0    
Wildfire-related claims, ending balance   0.0    
Trade creditors, ending balance   0.0    
Non-qualified benefit plan, ending balance   0.0    
2001 bankruptcy disputed claims, ending balance   0.0    
Customer deposits & advances, ending balance   0.0    
Other, ending balance   0.0    
Liabilities Subject to Compromise, ending balance   0.0    
Accounts payable - other   624.0   675.0
Disputed claims and customer refunds   242.0   0.0
Interest payable   444.0   4.0
Short-term borrowings   3,547.0   0.0
Other   2,248.0   1,263.0
Other non-current liabilities   3,886.0   2,626.0
Pension and other postretirement benefits   2,328.0   1,884.0
Accounts payable - trade creditors   2,366.0   1,949.0
Wildfire-related claims   2,250.0   0.0
Pacific Gas & Electric Co (Utility) | Subsequent Event        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Accounts payable, trade     $ 941.0  
PG&E Corporation        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Financing debt, beginning balance 666.0 666.0    
Wildfire-related claims, beginning balance 0.0 0.0    
Trade creditors, beginning balance 5.0 5.0    
Non-qualified benefit plan, beginning balance 137.0 137.0    
2001 bankruptcy disputed claims, beginning balance 0.0 0.0    
Customer deposits & advances, beginning balance 0.0 0.0    
Other, beginning balance 2.0 2.0    
Liabilities Subject to Compromise, beginning balance $ 810.0 810.0    
Financing debt, ending balance   0.0    
Wildfire-related claims, ending balance   0.0    
Trade creditors, ending balance   0.0    
Non-qualified benefit plan, ending balance   0.0    
2001 bankruptcy disputed claims, ending balance   0.0    
Customer deposits & advances, ending balance   0.0    
Other, ending balance   0.0    
Liabilities Subject to Compromise, ending balance   0.0    
Long-term debt, classified as current   28.0   0.0
Other   72.0   3.0
Other non-current liabilities   $ 191.0   $ 58.0
PG&E Corporation | Subsequent Event        
Liabilities Subject to Compromise, Period Increase (Decrease) [Roll Forward]        
Accounts payable, trade     $ 5.0  
v3.20.4
BANKRUPTCY FILING (Chapter 11 Claims Process) (Details)
proofOfClaim in Thousands, claim in Thousands, $ in Billions
Oct. 27, 2020
Dec. 31, 2020
proofOfClaim
lawsuit
claim
Dec. 31, 2019
USD ($)
Debt Instrument [Line Items]      
Proofs of claims | proofOfClaim   100  
Insurance from wildfire events | $     $ 2.5
Deadline extension period 180 days    
Subrogation Wildfire Trust and Fire Victim Trust      
Debt Instrument [Line Items]      
Proofs of claims | claim   80  
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt      
Debt Instrument [Line Items]      
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit   3  
v3.20.4
BANKRUPTCY FILING (Reorganization Items, Net) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Pacific Gas & Electric Co (Utility)    
Debt Instrument [Line Items]    
Payments (refunds) for reorganization items $ 400 $ 223
Probable of recovery 35  
PG&E Corporation    
Debt Instrument [Line Items]    
Payments (refunds) for reorganization items $ 102 $ 15
v3.20.4
BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Reorganizations [Line Items]      
Debtor-in-possession financing costs $ 6 $ 114  
Legal and other 1,969 292  
Interest income (16) (60)  
Total reorganization items, net 1,959 346 $ 0
Equity backstop premium expense and bridge loan facility fees      
Reorganizations [Line Items]      
Legal and other 1,500    
PG&E Corporation      
Reorganizations [Line Items]      
Debtor-in-possession financing costs 0 17  
Legal and other 1,651 19  
Interest income (2) (10)  
Total reorganization items, net 1,649 26 0
Pacific Gas & Electric Co (Utility)      
Reorganizations [Line Items]      
Debtor-in-possession financing costs 6 97  
Legal and other 318 273  
Interest income (14) (50)  
Total reorganization items, net $ 310 $ 320 $ 0
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details)
 12 Months Ended
Dec. 31, 2020
USD ($)
numberOfFatality
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Dec. 30, 2020
USD ($)
Oct. 05, 2020
USD ($)
Jul. 12, 2019
USD ($)
Public Utility, Property, Plant and Equipment [Line Items]            
Period for probable revenue recovery 24 months          
Expected wildfire fund allocation metric, initial contribution           $ 4,800,000,000
Expected wildfire fund allocation metric, annual contributions           $ 193,000,000
Expected wildfire fund allocation metric, annual contributions, second       $ 193,000,000    
Litigation liability, current $ 193,000,000          
Wildfire fund asset 464,000,000 $ 0        
Litigation contribution, net 5,800,000,000          
Amortization and accretion $ 413,000,000 0 $ 0      
Monte carlo simulation, historical data, period 12 years          
Amortization period 6 years          
Percentage assumption change 10.00%          
Greater effectiveness, amortization period 17 years          
Less effectiveness, amortization period 12 years          
Operating lease, payments $ 2,500,000,000 $ 2,400,000,000        
Weighted average remaining lease term 5 years 8 months 12 days 5 years 10 months 24 days        
Weighted average discount rate 6.20% 6.20%        
Allowance for credit loss $ 150,000,000          
Regulatory assets, probable recovery 76,000,000          
Regulatory assets, deferred amount $ 10,000,000          
Five Year Historical Period            
Public Utility, Property, Plant and Equipment [Line Items]            
Historical data period 5 years          
Average annual statewide claims or settlements $ 6,500,000,000          
Twelve Year Historical Period            
Public Utility, Property, Plant and Equipment [Line Items]            
Historical data period 12 years          
Average annual statewide claims or settlements $ 2,900,000,000          
Wildfire Fund Asset            
Public Utility, Property, Plant and Equipment [Line Items]            
Finite-lived intangible asset, useful life 15 years          
Noncurrent liabilities – other            
Public Utility, Property, Plant and Equipment [Line Items]            
Wildfire fund, noncurrent $ 1,300,000,000          
Pacific Gas & Electric Co (Utility)            
Public Utility, Property, Plant and Equipment [Line Items]            
Composite depreciation rate 3.76% 3.80% 3.82%      
AFUDC debt recorded $ 35,000,000 $ 55,000,000 $ 53,000,000      
AFUDC equity recorded 140,000,000 79,000,000 129,000,000      
Nuclear decommissioning obligation accrued 5,100,000,000 4,900,000,000        
Estimated cost recovery on spent nuclear fuel storage proceeding every year 10,600,000,000 10,600,000,000        
Wildfire fund asset 464,000,000 0        
Amortization and accretion 413,000,000 $ 0 $ 0      
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program            
Public Utility, Property, Plant and Equipment [Line Items]            
Aggregate maximum amount of loans made by lenders 1,000,000,000.0       $ 1,000,000,000.0  
Long-term debt, gross $ 1,000,000,000.0          
Pacific Gas & Electric Co (Utility) | Diablo Canyon            
Public Utility, Property, Plant and Equipment [Line Items]            
Number of generation facilities | numberOfFatality 2          
Pacific Gas & Electric Co (Utility) | Humboldt Bay            
Public Utility, Property, Plant and Equipment [Line Items]            
Number of generation facilities | numberOfFatality 1          
PG&E AR Facility, LLC (SPV) | Receivables Securitization Program            
Public Utility, Property, Plant and Equipment [Line Items]            
Accounts receivable, net $ 2,600,000,000          
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Revenue from contracts with customers      
Total operating revenues $ 18,469 $ 17,129 $ 16,759
Electric      
Revenue from contracts with customers      
Total operating revenues 13,858 12,740 12,713
Natural gas      
Revenue from contracts with customers      
Total operating revenues 4,611 4,389 4,046
Pacific Gas & Electric Co (Utility)      
Revenue from contracts with customers      
Total operating revenues 18,469 17,129 16,760
Pacific Gas & Electric Co (Utility) | Electric      
Revenue from contracts with customers      
Total operating revenues 13,185 12,437  
Regulatory balancing accounts 673 303  
Total operating revenues 13,858 12,740 12,713
Pacific Gas & Electric Co (Utility) | Electric | Residential      
Revenue from contracts with customers      
Total operating revenues 5,523 4,847  
Pacific Gas & Electric Co (Utility) | Electric | Commercial      
Revenue from contracts with customers      
Total operating revenues 4,722 4,756  
Pacific Gas & Electric Co (Utility) | Electric | Industrial      
Revenue from contracts with customers      
Total operating revenues 1,530 1,493  
Pacific Gas & Electric Co (Utility) | Electric | Agricultural      
Revenue from contracts with customers      
Total operating revenues 1,471 1,106  
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting      
Revenue from contracts with customers      
Total operating revenues 69 67  
Pacific Gas & Electric Co (Utility) | Electric | Other      
Revenue from contracts with customers      
Total operating revenues (130) 168  
Pacific Gas & Electric Co (Utility) | Natural gas      
Revenue from contracts with customers      
Total operating revenues 4,386 4,302  
Regulatory balancing accounts 225 87  
Total operating revenues 4,611 4,389 $ 4,047
Pacific Gas & Electric Co (Utility) | Natural gas | Residential      
Revenue from contracts with customers      
Total operating revenues 2,517 2,325  
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial      
Revenue from contracts with customers      
Total operating revenues 597 605  
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only      
Revenue from contracts with customers      
Total operating revenues 1,211 1,249  
Pacific Gas & Electric Co (Utility) | Natural gas | Other      
Revenue from contracts with customers      
Total operating revenues $ 61 $ 123  
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utilities Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co (Utility) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 93,892 $ 88,088
Accumulated depreciation (27,756) (26,453)
Net property, plant, and equipment 66,136 61,635
Electricity generating facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 13,751 13,189
Electricity generating facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 5 years  
Electricity generating facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 75 years  
Electricity distribution facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 37,675 35,237
Electricity distribution facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 10 years  
Electricity distribution facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 70 years  
Electricity transmission facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 15,556 14,281
Electricity transmission facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 15 years  
Electricity transmission facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 75 years  
Natural gas distribution facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 15,133 14,236
Natural gas distribution facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 20 years  
Natural gas distribution facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 60 years  
Natural gas transmission and storage facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 9,002 8,452
Natural gas transmission and storage facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 5 years  
Natural gas transmission and storage facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 66 years  
Construction work in progress    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 2,757 2,675
Other    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 18 $ 18
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
ARO liability at beginning of year $ 5,854 $ 5,994
Liabilities incurred in the current period 268 0
Revision in estimated cash flows 53 (376)
Accretion 265 274
Liabilities settled (28) (38)
ARO liability at end of year $ 6,412 $ 5,854
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Accumulated Other Comprehensive Loss    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Beginning balance $ (5) $ (4)
Net current period other comprehensive loss (17) (1)
Ending balance (22) (5)
Accumulated Other Comprehensive Loss | Pension Plan    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Beginning balance (22) (21)
Net current period other comprehensive loss (17) (1)
Ending balance (39) (22)
Accumulated Other Comprehensive Loss | PBOP Plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Beginning balance 17 17
Net current period other comprehensive loss 0 0
Ending balance 17 17
Amortization of prior service cost    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income: 6 6
Amortization of prior service cost | Pension Plan    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income: (4) (4)
Amounts reclassified from other comprehensive income, tax 2 2
Amortization of prior service cost | PBOP Plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income: 10 10
Amounts reclassified from other comprehensive income, tax 4 4
Amortization of net actuarial gain (loss)    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: (247) 288
Amounts reclassified from other comprehensive income: (13) 0
Amortization of net actuarial gain (loss) | Pension Plan    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: (417) 61
Amounts reclassified from other comprehensive income: 2 2
Other comprehensive income before reclassifications, tax 162 24
Amounts reclassified from other comprehensive income, tax 1 1
Amortization of net actuarial gain (loss) | PBOP Plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 170 227
Amounts reclassified from other comprehensive income: (15) (2)
Other comprehensive income before reclassifications, tax 66 88
Amounts reclassified from other comprehensive income, tax 6 1
Regulatory account transfer    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 230 (289)
Amounts reclassified from other comprehensive income: 7 (6)
Regulatory account transfer | Pension Plan    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 400 (62)
Amounts reclassified from other comprehensive income: 2 2
Other comprehensive income before reclassifications, tax 155 24
Amounts reclassified from other comprehensive income, tax 1 1
Regulatory account transfer | PBOP Plans    
AOCI Attributable to Parent, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: (170) (227)
Amounts reclassified from other comprehensive income: 5 (8)
Other comprehensive income before reclassifications, tax 66 88
Amounts reclassified from other comprehensive income, tax $ 2 $ 3
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Accounting Policies [Abstract]    
Operating lease fixed cost $ 679 $ 686
Operating lease variable cost 1,852 1,778
Total operating lease cost $ 2,531 $ 2,464
v3.20.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Future Expected Operating Lease Payments  
2021 $ 624
2022 550
2023 257
2024 98
2025 91
Thereafter 513
Total lease payments 2,133
Less imputed interest (397)
Total $ 1,736
v3.20.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 8,978 $ 6,066
Utility retained generation asset costs 1,200  
Pension benefits    
Regulatory Assets [Line Items]    
Total long-term regulatory assets 2,245 1,823
Environmental compliance costs    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 1,112 1,062
Recovery Period 32 years  
Utility retained generation    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 181 228
Recovery Period 6 years  
Price risk management    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 204 124
Recovery Period 19 years  
Unamortized loss, net of gain, on reacquired debt    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 49 63
Recovery Period 23 years  
Catastrophic event memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 842 656
Catastrophic event memorandum account | COVID-19    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 49  
Catastrophic event memorandum account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Catastrophic event memorandum account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
Wildfire expense memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 400 423
Wildfire expense memorandum account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Wildfire expense memorandum account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
Fire hazard prevention memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 137 259
Fire hazard prevention memorandum account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Fire hazard prevention memorandum account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
Fire risk mitigation memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 66 95
Fire risk mitigation memorandum account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Fire risk mitigation memorandum account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
Wildfire mitigation plan memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 390 558
Wildfire mitigation plan memorandum account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Wildfire mitigation plan memorandum account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
Deferred income tax    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 908 252
Recovery Period 51 years  
Insurance premium costs    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 294 0
Insurance premium costs | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Insurance premium costs | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 4 years  
Wildfire mitigation balancing account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 156 0
Wildfire mitigation balancing account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Cost percentage threshold requiring approval 115.00%  
Wildfire mitigation balancing account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
General rate case memorandum accounts    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 376 0
General rate case memorandum accounts | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
General rate case memorandum accounts | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 2 years  
Vegetation management balancing account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 592 0
Vegetation management balancing account | Minimum    
Regulatory Assets [Line Items]    
Recovery Period 1 year  
Cost percentage threshold requiring approval 120.00%  
Vegetation management balancing account | Maximum    
Regulatory Assets [Line Items]    
Recovery Period 3 years  
COVID-19 Pandemic protection memorandum account    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 84 0
COVID-19 pandemic protection memorandum account, undercollection bad debt    
Regulatory Assets [Line Items]    
Total long-term regulatory assets 76  
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs    
Regulatory Assets [Line Items]    
Total long-term regulatory assets 8  
Other    
Regulatory Assets [Line Items]    
Total long-term regulatory assets $ 942 $ 523
v3.20.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities $ 10,424 $ 9,270
Cost of removal obligations    
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities 6,905 6,456
Recoveries in excess of AROs    
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities 458 393
Public purpose programs    
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities 948 817
Retirement Plan    
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities 995 750
Other    
Regulatory Liabilities [Line Items]    
Total long-term regulatory liabilities $ 1,118 $ 854
v3.20.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Regulatory Liabilities [Line Items]    
Regulatory balancing accounts $ 410 $ 315
Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 1,245 1,797
Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 2,001 2,114
Electric distribution | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 55 31
Electric transmission | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 267 119
Electric transmission | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 0 9
Gas distribution and transmission | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 76 45
Gas distribution and transmission | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 102 363
Energy procurement | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 158 649
Energy procurement | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 413 901
Public purpose programs | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 410 559
Public purpose programs | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 292 209
Fire hazard prevention memorandum account | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 121 0
Fire risk mitigation memorandum account | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 33 0
Wildfire mitigation plan memorandum account | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 161 0
Wildfire mitigation balancing account | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 27 0
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 313 0
Vegetation management balancing account | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 115 0
Insurance premium costs    
Regulatory Liabilities [Line Items]    
Regulatory balancing accounts 93  
Insurance premium costs | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 135 0
Other | Regulatory Balancing Accounts Payable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts 279 394
Other | Regulatory Balancing Accounts Receivable    
Regulatory Liabilities [Line Items]    
Total regulatory balancing accounts $ 289 $ 632
v3.20.4
DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)
Dec. 31, 2020
Jul. 01, 2020
Revolving Credit Facility    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 8,000,000,000  
Borrowings Outstanding 4,605,000,000  
Letters of Credit Outstanding 1,020,000,000  
Facility Availability 2,375,000,000  
Revolving Credit Facility | PG&E Corporation    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity 500,000,000 $ 500,000,000
Borrowings Outstanding 0  
Letters of Credit Outstanding 0  
Facility Availability 500,000,000  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity 3,500,000,000 3,500,000,000
Borrowings Outstanding 605,000,000  
Letters of Credit Outstanding 1,020,000,000  
Facility Availability 1,875,000,000  
Letter of credit sublimit 1,500,000,000  
Term Loan | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity 3,000,000,000  
Borrowings Outstanding 3,000,000,000  
Letters of Credit Outstanding 0  
Facility Availability 0  
Term Loan, June 2021 | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity   1,500,000,000
Term Loan, January 2022 | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity   $ 1,500,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity 1,000,000,000  
Borrowings Outstanding 1,000,000,000.0  
Letters of Credit Outstanding 0  
Facility Availability $ 0  
v3.20.4
DEBT (Credit Facility) (Details)
Jul. 01, 2020
USD ($)
numberOfExtensionOption
numberOfClaimHolder
Dec. 31, 2020
USD ($)
Revolving Credit Facility    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity   $ 8,000,000,000
Revolving Credit Facility | PG&E Corporation    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 500,000,000 500,000,000
Debt instrument, term 3 years  
Debt, number of extension options | numberOfExtensionOption 2  
Debt instrument, extension option, term 1 year  
Percentage of ownership of outstanding common stock 100.00%  
Revolving Credit Facility | PG&E Corporation | Minimum    
Debt [Line Items]    
Facility fee 0.50%  
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance 150.00%  
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared 100.00%  
Revolving Credit Facility | PG&E Corporation | Minimum | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 3.00%  
Revolving Credit Facility | PG&E Corporation | Minimum | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 2.00%  
Revolving Credit Facility | PG&E Corporation | Maximum    
Debt [Line Items]    
Facility fee 0.75%  
Debt, ratio of total consolidated debt to consolidated capitalization 70.00%  
Debt default, amount $ 200,000,000  
Revolving Credit Facility | PG&E Corporation | Maximum | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 4.25%  
Revolving Credit Facility | PG&E Corporation | Maximum | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 3.25%  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 3,500,000,000 $ 3,500,000,000
Debt instrument, term 3 years  
Debt, number of extension options | numberOfClaimHolder 2  
Debt instrument, extension option, term 1 year  
Letter of credit, maximum borrowing capacity $ 1,500,000,000  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum    
Debt [Line Items]    
Facility fee 0.25%  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 1.375%  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Minimum | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 0.375%  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum    
Debt [Line Items]    
Facility fee 0.50%  
Debt, ratio of total consolidated debt to consolidated capitalization 65.00%  
Debt default, amount $ 200,000,000  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 2.50%  
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 1.50%  
Term Loan Credit Facility | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 3,000,000,000.0  
Debt, percentage of net cash proceeds from certain securitization transactions prepayment 100.00%  
Term Loan Credit Facility | Pacific Gas & Electric Co (Utility) | Maximum    
Debt [Line Items]    
Debt, ratio of total consolidated debt to consolidated capitalization 65.00%  
Debt default, amount $ 200,000,000  
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 1,500,000,000  
Debt instrument, term 364 days  
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 2.00%  
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 1.00%  
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility)    
Debt [Line Items]    
Line of credit facility, maximum borrowing capacity $ 1,500,000,000  
Debt instrument, term 18 months  
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR    
Debt [Line Items]    
Basis spread on variable rate 2.25%  
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate    
Debt [Line Items]    
Basis spread on variable rate 1.25%  
Second Amended and Restated Credit Agreement | PG&E Corporation    
Debt [Line Items]    
Repayments of debt $ 300,000,000  
v3.20.4
DEBT (Receivables Securitization Program) (Details) - USD ($)
Oct. 05, 2020
Dec. 31, 2020
Dec. 31, 2019
Line of Credit Facility [Line Items]      
Program termination period 180 days    
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)      
Line of Credit Facility [Line Items]      
Percentage pledged of equity interests 100.00%    
Aggregate maximum amount of loans made by lenders $ 1,000,000,000.0 $ 1,000,000,000.0  
Debt financial instrument   $ 1,000,000,000 $ 0
v3.20.4
DEBT (Other Short-term Borrowings and Long-term Debt) (Details) - USD ($)
Feb. 01, 2021
Jul. 01, 2020
Jun. 23, 2020
Dec. 31, 2020
Nov. 16, 2020
Jun. 19, 2020
PG&E Corporation            
Debt [Line Items]            
Debt instrument, redemption price, percentage     100.00%      
First Mortgage Bonds due November 15, 2021 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount         $ 1,450,000,000  
Floating Rate First Mortgage Bonds due June 16, 2022 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 500,000,000
First Mortgage Bonds due June 16, 2022 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 2,500,000,000
Stated interest rate           1.75%
First Mortgage Bonds due August 1, 2027 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 1,000,000,000.0
Stated interest rate           2.10%
First Mortgage Bonds due February 1, 2031 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 2,000,000,000.0
Stated interest rate           2.50%
First Mortgage Bonds due August 1, 2040 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 1,000,000,000.0
Stated interest rate           3.30%
First Mortgage Bonds due August 1, 2050 | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount           $ 1,925,000,000
Stated interest rate           3.50%
New Mortgage Bonds | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount   $ 11,900,000,000        
Utility Reinstated Senior Notes | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Debt instrument, face amount   9,600,000,000        
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Line of credit facility, maximum borrowing capacity   $ 1,500,000,000        
Debt instrument, term   18 months        
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | LIBOR            
Debt [Line Items]            
Basis spread on variable rate   2.25%        
18-Month Term Loan Facility | Pacific Gas & Electric Co (Utility) | Base Rate            
Debt [Line Items]            
Basis spread on variable rate   1.25%        
Term Loan | PG&E Corporation            
Debt [Line Items]            
Debt instrument, face amount     $ 2,750,000,000      
Debt instrument, quarterly reduction amount       $ 6,875,000    
Prepayment premium percentage     1.00%      
Repayments of debt   $ 350,000,000        
Term Loan | PG&E Corporation | LIBOR            
Debt [Line Items]            
Debt instrument, basis spread on alternative base rate     1.00%      
Term Loan | PG&E Corporation | LIBOR | Subsequent Event            
Debt [Line Items]            
Basis spread on variable rate 3.00%          
Term Loan | PG&E Corporation | Alternative Base Rate (ABR) Floor            
Debt [Line Items]            
Basis spread on variable rate     2.00%      
Term Loan | PG&E Corporation | Prime Rate            
Debt [Line Items]            
Debt instrument, basis spread on alternative base rate     0.50%      
Term Loan | PG&E Corporation | Alternative Base Rate (ABR) | Subsequent Event            
Debt [Line Items]            
Basis spread on variable rate 2.00%          
Term Loan | PG&E Corporation | Minimum | LIBOR            
Debt [Line Items]            
Basis spread on variable rate     1.00%      
Term Loan | PG&E Corporation | Maximum            
Debt [Line Items]            
Debt default, amount     $ 200,000,000      
Term Loan | Pacific Gas & Electric Co (Utility)            
Debt [Line Items]            
Line of credit facility, maximum borrowing capacity       $ 3,000,000,000    
Percentage of ownership of outstanding common stock     100.00%      
Term Loan, Repricing Amendment | PG&E Corporation | LIBOR            
Debt [Line Items]            
Basis spread on variable rate     4.50%      
Term Loan, Repricing Amendment | PG&E Corporation | Alternative Base Rate (ABR) Floor | Subsequent Event            
Debt [Line Items]            
Basis spread on variable rate 1.50%          
Term Loan, Repricing Amendment | PG&E Corporation | Alternative Base Rate (ABR)            
Debt [Line Items]            
Basis spread on variable rate     3.50%      
Term Loan, Repricing Amendment | PG&E Corporation | Minimum | LIBOR | Subsequent Event            
Debt [Line Items]            
Basis spread on variable rate 0.50%          
Senior Secured Notes due July 1, 2028 | PG&E Corporation            
Debt [Line Items]            
Debt instrument, face amount     $ 1,000,000,000.0      
Stated interest rate     5.00%      
Senior Secured Notes due July 1, 2030 | PG&E Corporation            
Debt [Line Items]            
Debt instrument, face amount     $ 1,000,000,000.0      
Stated interest rate     5.25%      
Senior Notes | PG&E Corporation            
Debt [Line Items]            
Debt instrument, redemption price, percentage     40.00%      
v3.20.4
DEBT (Schedule of Long-term Debt) (Details) - USD ($)
 12 Months Ended
Dec. 31, 2020
Jul. 01, 2020
Dec. 31, 2019
Pre-petition Long Term Debt | PG&E Corporation      
Debt [Line Items]      
Senior notes $ 0   $ 650,000,000
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation      
Debt [Line Items]      
Total Pre-Petition Pollution Control Bonds 0   $ 300,000,000
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation | LIBOR      
Debt [Line Items]      
Stated interest rate     3.24%
Term Loan - Stated Maturity: 2020 | PG&E Corporation      
Debt [Line Items]      
Debt 0   $ 350,000,000
Term Loan - Stated Maturity: 2020 | PG&E Corporation | LIBOR      
Debt [Line Items]      
Stated interest rate     2.96%
Pre-petition Senior Notes | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes 0   $ 17,525,000,000
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   1,750,000,000
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 2.45%    
Senior Notes Due 2020 Through 2022 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.25%    
First Mortgage Bonds Due 2025 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   3.45%  
Debt instrument, face amount   $ 875,000,000  
First Mortgage Bonds Due 2025 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   3.45%  
First Mortgage Bonds Due 2028 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   3.75%  
Debt instrument, face amount   $ 875,000,000  
First Mortgage Bonds Due 2028 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   3.75%  
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   5,025,000,000
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 2.95%    
Senior Notes Due 2023 Through 2028 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.65%    
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   5,700,000,000
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 5.40%    
Senior Notes Due 2034 Through 2040 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 6.35%    
First Mortgage Bonds Due 2030 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   4.55%  
Debt instrument, face amount   $ 3,100,000,000  
First Mortgage Bonds Due 2030 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   4.55%  
First Mortgage Bonds Due 2050 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   4.95%  
Debt instrument, face amount   $ 3,100,000,000  
First Mortgage Bonds Due 2050 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   4.95%  
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   1,000,000,000
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 3.75%    
Senior Notes Due 2041 Through 2042 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.50%    
Senior Notes Due 2043 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   500,000,000
Stated interest rate 5.13%    
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes $ 0   3,550,000,000
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 3.95%    
Senior Notes Due 2043 Through 2047 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.75%    
Pre-petition Pollution Control Bonds | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
PG&E Corporation $ 0   863,000,000
Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 0.0175%    
Pollution control bonds $ 0 $ 100,000,000 $ 100,000,000
Pollution Control Bonds Series 2009, A-B, Variable Rate, Due 2026 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate     7.95%
Pollution control bonds 0   $ 149,000,000
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Pollution control bonds 0   $ 614,000,000
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate     7.95%
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate     8.08%
Pre-Petition Credit Facility | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Senior notes 0   $ 3,138,000,000
Utility Revolving Credit Facilities - Stated Maturity: 2022 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Total Pre-Petition Pollution Control Bonds 0   $ 2,888,000,000
Utility Revolving Credit Facilities - Stated Maturity: 2022 | PG&E Corporation | LIBOR      
Debt [Line Items]      
Stated interest rate     3.04%
Term Loan - Stated Maturity: 2019 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Debt 0   $ 250,000,000
Term Loan - Stated Maturity: 2019 | PG&E Corporation | LIBOR      
Debt [Line Items]      
Stated interest rate     2.36%
First Mortgage Bonds Due 2026 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   3.15%  
Debt instrument, face amount   $ 1,950,000,000  
First Mortgage Bonds Due 2040 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate   4.50%  
Debt instrument, face amount   $ 1,950,000,000  
Pre-Petition Debt      
Debt [Line Items]      
Long-term debt 0   $ 22,176,000,000
Pre-Petition Debt | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt 0   21,526,000,000
Debt instrument, face amount     17,900,000,000
New Debt      
Debt [Line Items]      
Long-term debt 37,288,000,000   0
New Debt | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt 32,664,000,000   0
Unamortized discount, net of premium and debt issuance costs (6,000,000)   0
New Debt | PG&E Corporation      
Debt [Line Items]      
Long-term debt 4,624,000,000   0
Unamortized discount, net of premium and debt issuance costs (85,000,000)   0
Term Loan, Stated Maturity 2025 | PG&E Corporation      
Debt [Line Items]      
Long-term debt, gross $ 2,709,000,000   0
Term Loan, Stated Maturity 2025 | PG&E Corporation | LIBOR      
Debt [Line Items]      
Stated interest rate 5.50%    
Senior Notes Due 2028 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate 5.00%    
Long-term debt, gross $ 1,000,000,000   0
Senior Notes Due 2030 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate 5.25%    
Long-term debt, gross $ 1,000,000,000   0
18-Months Term Loan | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Debt $ 1,500,000,000   0
Debt Instrument, term 18 months    
18-Months Term Loan | Pacific Gas & Electric Co (Utility) | LIBOR      
Debt [Line Items]      
Stated interest rate 2.44%    
First Mortgage Bonds, Reinstated | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt $ 9,575,000,000   0
Unamortized discount, net of premium and debt issuance costs 0   0
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt, gross $ 5,025,000,000   0
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 2.95%    
First Mortgage Bonds, Reinstated Stated Maturity 2023 through 2028 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.65%    
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt, gross $ 1,000,000,000   0
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 3.75%    
First Mortgage Bonds, Reinstated Stated Maturity 2041 through 2042 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.50%    
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt, gross $ 3,550,000,000   0
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility) | Minimum      
Debt [Line Items]      
Stated interest rate 3.95%    
First Mortgage Bonds, Reinstated Stated Maturity 2043 through 2047 | Pacific Gas & Electric Co (Utility) | Maximum      
Debt [Line Items]      
Stated interest rate 4.75%    
First Mortgage Bonds, Exchange | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt $ 11,754,000,000   0
Unamortized discount, net of premium and debt issuance costs $ (98,000,000)   0
First Mortgage Bonds, Exchange Stated Maturity 2025 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 3.45%    
Long-term debt, gross $ 875,000,000   0
First Mortgage Bonds, Exchange Stated Maturity 2025 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   3.15%  
First Mortgage Bonds, Exchange Stated Maturity 2026 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 3.15%    
Long-term debt, gross $ 1,951,000,000   0
First Mortgage Bonds, Exchange Stated Maturity 2028 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 3.75%    
Long-term debt, gross $ 875,000,000   0
First Mortgage Bonds, Exchange Stated Maturity 2030 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 4.55%    
Long-term debt, gross $ 3,100,000,000   0
First Mortgage Bonds, Exchange Stated Maturity 2040 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 4.50%    
Long-term debt, gross $ 1,951,000,000   0
First Mortgage Bonds, Exchange Stated Maturity 2040 | PG&E Corporation      
Debt [Line Items]      
Stated interest rate   4.50%  
First Mortgage Bonds, Exchange Stated Maturity 2050 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 4.95%    
Long-term debt, gross $ 3,100,000,000   0
First Mortgage Bonds | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt 8,841,000,000   0
Unamortized discount, net of premium and debt issuance costs (84,000,000)   0
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt, gross $ 500,000,000   0
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility) | LIBOR      
Debt [Line Items]      
Stated interest rate 1.70%    
First Mortgage Bonds, Stated Maturity 2022 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 1.75%    
Long-term debt, gross $ 2,500,000,000   0
First Mortgage Bonds, Stated Maturity 2027 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 2.10%    
Long-term debt, gross $ 1,000,000,000   0
First Mortgage Bonds, Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 2.50%    
Long-term debt, gross $ 2,000,000,000   0
First Mortgage Bonds, Stated Maturity 2040 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 3.30%    
Long-term debt, gross $ 1,000,000,000   0
First Mortgage Bonds, Stated Maturity 2050 | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Stated interest rate 3.50%    
Long-term debt, gross $ 1,925,000,000   0
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)      
Debt [Line Items]      
Long-term debt 1,000,000,000   $ 0
Long-term debt, gross $ 1,000,000,000.0    
v3.20.4
DEBT (Schedule of Contractual Repayment Schedule) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2020
USD ($)
Debt [Line Items]  
Total consolidated debt $ 37,589
Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 3.66%
Fixed rate obligations $ 29,852
Variable rate obligations $ 3,000
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan  
Debt [Line Items]  
Debt Instrument, term 18 months
Pacific Gas & Electric Co (Utility) | 18-Months Term Loan | LIBOR  
Debt [Line Items]  
Debt, average interest rate 2.44%
Pacific Gas & Electric Co (Utility) | Receivables Securitization Program | LIBOR  
Debt [Line Items]  
Debt, average interest rate 1.57%
Pacific Gas & Electric Co (Utility) | First Mortgage Bonds, Stated Maturity 2022 | LIBOR  
Debt [Line Items]  
Debt, average interest rate 1.70%
PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 5.13%
Fixed rate obligations $ 2,000
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 2,737
2021  
Debt [Line Items]  
Total consolidated debt $ 28
2021 | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
2021 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 28
2022  
Debt [Line Items]  
Total consolidated debt $ 5,528
2022 | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 1.75%
Fixed rate obligations $ 2,500
Variable rate obligations $ 3,000
2022 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 28
2023  
Debt [Line Items]  
Total consolidated debt $ 1,203
2023 | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 3.83%
Fixed rate obligations $ 1,175
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
2023 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 28
2024  
Debt [Line Items]  
Total consolidated debt $ 828
2024 | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 3.60%
Fixed rate obligations $ 800
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
2024 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 28
2025  
Debt [Line Items]  
Total consolidated debt $ 4,100
2025 | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 3.47%
Fixed rate obligations $ 1,475
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
2025 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
Variable interest rate as of December 31, 2020 5.50%
Variable rate obligations $ 2,625
Thereafter  
Debt [Line Items]  
Total consolidated debt $ 25,902
Thereafter | Pacific Gas & Electric Co (Utility)  
Debt [Line Items]  
Average fixed interest rate 3.87%
Fixed rate obligations $ 23,902
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
Thereafter | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 5.13%
Fixed rate obligations $ 2,000
Variable interest rate as of December 31, 2020 0.00%
Variable rate obligations $ 0
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details)
$ / shares in Units, purchaseContract in Thousands, equityUnit in Thousands
 1 Months Ended 3 Months Ended 12 Months Ended 72 Months Ended
Aug. 03, 2020
USD ($)
equityUnit
shares
Jul. 01, 2020
USD ($)
shares
Jun. 25, 2020
USD ($)
equityUnit
purchaseContract
shares
Jun. 07, 2020
USD ($)
$ / shares
May 28, 2020
Jul. 31, 2020
USD ($)
Jun. 30, 2020
USD ($)
Dec. 31, 2020
USD ($)
$ / shares
shares
Dec. 31, 2019
USD ($)
$ / shares
shares
Dec. 31, 2018
USD ($)
$ / shares
Dec. 31, 2020
USD ($)
shares
Jun. 22, 2020
shares
Mar. 20, 2020
USD ($)
Schedule of Capitalization, Equity [Line Items]                          
Common stock, shares outstanding (in shares)               1,984,678,673 529,236,741   1,984,678,673    
Common stock, shares authorized (in shares)               3,600,000,000 800,000,000   3,600,000,000 3,600,000,000  
Preferred stock, shares authorized (in shares)                       400,000,000  
Equity Units issued | $   $ 9,000,000,000.0 $ 3,970,000,000     $ 9,000,000,000.0   $ 1,304,000,000 $ 0 $ 0      
Sale of stock, consideration received on transaction | $       $ 3,250,000,000                  
Sale of stock, price per share (in dollars per share) | $ / shares       $ 9.50                  
Sale of stock, number of shares issued in transaction (in shares)   342,100,000                      
Proceeds from issuance or sale of equity, net | $   $ 5,200,000,000 $ 1,190,000,000                    
Proceeds from equity backstop commitments and forward stock purchase agreements | $               523,000,000          
Sale of stock, redemption of rights, return amount | $ $ 120,500,000                        
Sale of stock, issuance and delivery, common stock (in shares) 42,300,000                        
Transfer of shares to Fire Victim Trust (in shares)   477,000,000.0                      
Transfer of shares to Fire Victim Trust, additional (in shares) 748,415                        
Equity contribution cash | $               $ 12,900,000,000     $ 12,900,000,000    
Percentage of equity security ownership with board of director approval               4.75%     4.75%    
Deferred tax asset, litigation adjustment | $             $ 619,000,000            
Dividend reinstatement target, amount | $                         $ 6,200,000,000
Equity capital structure percentage   52.00%                      
Equity capital structure, waiver period         5 years                
Number of shares issued for LTIP, maximum (in shares)               17,000,000     17,000,000    
Shares available for LTIP award (in shares)               29,174,205     29,174,205    
Weighted average grant date fair value of granted shares (in dollars per share) | $ / shares               $ 9.25 $ 18.57 $ 40.92      
Total fair value | $               $ 31,000,000 $ 42,000,000 $ 41,000,000      
Total unrecognized compensation costs | $               $ 6,000,000          
Remaining weighted average period               1 year 6 months 29 days          
Fire Trust Victim                          
Schedule of Capitalization, Equity [Line Items]                          
Transfer of shares to Fire Victim Trust (in shares)   477,000,000                      
Transfer of shares to Fire Victim Trust, additional (in shares) 748,415                        
Litigation liability, payment accrual | $                 $ 6,750,000,000        
Transfer of shares related to litigation settlement, value | $             4,530,000,000            
Difference between payment accrual and transfer of shares related to litigation settlement, value | $             $ 2,200,000,000            
Minimum                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of equity units, right to receive 125,000,000                        
Sale of stock, number of additional units, right to receive (in shares) 12,500,000                        
Maximum                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of equity units, right to receive 153,000,000                        
Sale of stock, number of additional units, right to receive (in shares) 15,300,000                        
2014 LTIP, Amended                          
Schedule of Capitalization, Equity [Line Items]                          
Number of shares issued for LTIP, maximum (in shares)               47,000,000     47,000,000    
Stock Options                          
Schedule of Capitalization, Equity [Line Items]                          
Granted (in shares)               0          
Tax benefit from share based awards | $               $ 0          
Weighted-average period               2 years 2 months 12 days          
Stock Options | 2014 LTIP                          
Schedule of Capitalization, Equity [Line Items]                          
Term of award               10 years          
Award vesting period               3 years          
Total unrecognized compensation costs | $               $ 500,000     $ 500,000    
Weighted average grant date fair value of granted shares (in dollars per share) | $ / shares                 $ 3.87        
Granted (in shares)               20,065          
Restricted stock units                          
Schedule of Capitalization, Equity [Line Items]                          
Award vesting period                     3 years    
Tax detriment | $               $ 19,000,000          
Performance shares                          
Schedule of Capitalization, Equity [Line Items]                          
Award vesting period               3 years          
Tax detriment | $               $ 49,000,000          
Industry performance period               3 years          
Award grant date fair value recognition period               3 years          
Performance shares granted (in dollars per share) | $ / shares               $ 9.62 $ 15.39 $ 36.92      
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized | $               $ 54,000,000          
Common Stock Offering                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of shares issued in transaction (in shares)     423,400,000                    
Option to purchase additional stock (in shares) 42,300,000   42,300,000                    
Equity Units Offering                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of equity units issued in transaction (in equity units) | equityUnit     14,500                    
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction (in purchase contracts) | purchaseContract     14,500                    
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction, additional contracts (in purchase contracts) | purchaseContract     1,450                    
Option to purchase additional contracts (in equity units) | equityUnit 1,450                        
Sale of stock, number of equity units issued and sold in transaction, additional (in equity units) | equityUnit 1,450                        
Common Stock Underwriters                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of shares issued and sold in transaction (in shares)     423,400,000                    
Equity Units Underwriters                          
Schedule of Capitalization, Equity [Line Items]                          
Sale of stock, number of prepaid forward stock purchase contracts issued and sold in transaction (in purchase contracts) | purchaseContract     14,500                    
PG&E Corporation                          
Schedule of Capitalization, Equity [Line Items]                          
Preferred stock, shares authorized (in shares)               400,000,000     400,000,000    
Equity Units issued | $               $ 1,304,000,000 $ 0 $ 0      
unrecognized compensation cost, period               1 month 28 days          
PG&E Corporation | Minimum | Revolving Credit Facility                          
Schedule of Capitalization, Equity [Line Items]                          
Debt, ratio of total consolidated debt to consolidated capitalization, loans outstanding balance   150.00%                      
Debt, ratio of total consolidated debt to consolidated capitalization, cash dividend declared   100.00%                      
PG&E Corporation | Maximum | Revolving Credit Facility                          
Schedule of Capitalization, Equity [Line Items]                          
Debt, ratio of total consolidated debt to consolidated capitalization   70.00%                      
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) $ 35 $ 50 $ 89
Total compensation expense (after-tax) 25 35 63
Stock Options      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) 3 7 10
Restricted stock units      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) 15 21 43
Performance shares      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) $ 17 $ 22 $ 36
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Significant Assumptions Used for Shares Granted) (Details) - 2014 LTIP - Stock Options
 12 Months Ended
Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Expected stock price volatility 57.00%
Expected annual dividend payment 0.00%
Expected life (years) 4 years 6 months
Minimum  
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Risk-free interest rate 1.51%
Maximum  
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Risk-free interest rate 1.52%
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Stock Options
 12 Months Ended
Dec. 31, 2020
$ / shares
shares
Number of Stock Options  
Granted (in shares) 0
2014 LTIP  
Number of Stock Options  
Outstanding, beginning of period (in shares) 4,281,403
Granted (in shares) 20,065
Exercised (in shares) 0
Forfeited or expired (in shares) (2,080,221)
Outstanding, end of period (in shares) 2,221,247
Vested or expected to vest (in shares) 2,215,076
Exercisable (in shares) 1,840,893
Weighted Average Grant- Date Fair Value  
Outstanding, beginning of period (in dollars per share) | $ / shares $ 5.98
Granted (in dollars per share) | $ / shares 3.87
Forfeited or expired (in dollars per share) | $ / shares 3.87
Outstanding, end of period (in dollars per share) | $ / shares 7.45
Vested or expected to vest (in dollars per share) | $ / shares 7.43
Exercisable (in dollars per share) | $ / shares $ 6.86
Weighted Average Remaining Contractual Term  
Outstanding 5 years 3 months 29 days
Expected to vest 5 years 3 months 21 days
Exercisable 4 years 11 months 4 days
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Number of Restricted Stock Units      
Nonvested, beginning balance (in shares) 1,040,835    
Granted (in shares) 1,007,782    
Vested (in shares) (944,090)    
Forfeited (in shares) (214,174)    
Nonvested, ending balance (in shares) 890,353 1,040,835  
Weighted Average Grant- Date Fair Value      
Nonvested, beginning balance (in dollars per share) $ 44.06    
Granted (in dollars per share) 9.25 $ 18.57 $ 40.92
Vested (in dollars per share) 33.14    
Forfeited (in dollars per share) 15.75    
Nonvested, ending balance (in dollars per share) $ 23.05 $ 44.06  
v3.20.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Number of Performance Shares      
Nonvested , beginning balance (in shares) 688,423    
Granted (in shares) 7,951,541    
Vested (in shares) (132,526)    
Forfeited (in shares) (1,218,656)    
Nonvested, ending balance (in shares) 7,288,782 688,423  
Weighted Average Grant- Date Fair Value      
Nonvested, beginning balance (in dollars per share) $ 36.92    
Granted (in dollars per share) 9.62 $ 15.39 $ 36.92
Vested (in dollars per share) 41.27    
Forfeited (in dollars per share) 24.38    
Nonvested, ending balance (in dollars per share) 9.16 $ 36.92  
Expirations, fair value (in dollars per share) $ 0    
v3.20.4
PREFERRED STOCK (Narrative) (Details) - USD ($)
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Jun. 22, 2020
Preferred Stock [Line Items]        
Preferred stock, shares authorized (in shares)       400,000,000
Pacific Gas & Electric Co (Utility)        
Preferred Stock [Line Items]        
Preferred stock dividend $ 0 $ 0 $ 0  
Pacific Gas & Electric Co (Utility) | Minimum        
Preferred Stock [Line Items]        
Redemption price (in dollars per share) $ 25.75 $ 25.75    
Pacific Gas & Electric Co (Utility) | Maximum        
Preferred Stock [Line Items]        
Redemption price (in dollars per share) $ 27.25 $ 27.25    
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock        
Preferred Stock [Line Items]        
Nonredeemable preferred stock outstanding $ 145,000,000 $ 145,000,000    
Preferred stock dividends per share, low range (in dollars per share) $ 1.25      
Preferred stock dividends per share, high range (in dollars per share) $ 1.50      
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Minimum        
Preferred Stock [Line Items]        
Preferred stock interest rate 5.00% 5.00%    
Pacific Gas & Electric Co (Utility) | Nonredeemable Preferred Stock | Maximum        
Preferred Stock [Line Items]        
Preferred stock interest rate 6.00% 6.00%    
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock        
Preferred Stock [Line Items]        
Redeemable preferred stock outstanding $ 113,000,000 $ 113,000,000    
Preferred stock dividends per share, low range (in dollars per share) $ 1.09      
Preferred stock dividends per share, high range (in dollars per share) $ 1.25      
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Minimum        
Preferred Stock [Line Items]        
Preferred stock interest rate 4.36% 4.36%    
Pacific Gas & Electric Co (Utility) | Redeemable Preferred Stock | Maximum        
Preferred Stock [Line Items]        
Preferred stock interest rate 5.00% 5.00%    
PG&E Corporation        
Preferred Stock [Line Items]        
Preferred stock, shares authorized (in shares) 400,000,000      
Preferred stock, shares outstanding (in shares) 0      
$100 Par Value | Pacific Gas & Electric Co (Utility)        
Preferred Stock [Line Items]        
Preferred stock, shares authorized (in shares) 10,000,000      
Preferred stock, shares outstanding (in shares) 0      
Preferred stock, par value (in dollars per share) $ 100      
$25 Par Value | Pacific Gas & Electric Co (Utility)        
Preferred Stock [Line Items]        
Preferred stock, shares authorized (in shares) 75,000,000      
Preferred stock, par value (in dollars per share) $ 25      
v3.20.4
EARNINGS PER SHARE (Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Shares of Common Stock Outstanding for Calculating Diluted EPS) (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Earnings Per Share [Abstract]      
Loss attributable to common shareholders $ (1,318) $ (7,656) $ (6,851)
Weighted average common shares outstanding, basic (in shares) 1,257 528 517
Add incremental shares from assumed conversions:      
Employee share-based compensation (in shares) 0 0 0
Equity Units (in shares) 0 0 0
Weighted average common share outstanding, diluted (in shares) 1,257 528 517
Total Loss per common share, diluted (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
v3.20.4
INCOME TAXES (Schedule of Income Tax Provision (Benefit)) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Current:      
Federal $ (26) $ 1 $ (5)
State (34) 101 (8)
Deferred:      
Federal 258 (2,361) (2,264)
State 171 (1,136) (1,009)
Tax credits (7) (5) (6)
Income tax provision (benefit) 362 (3,400) (3,292)
Pacific Gas & Electric Co (Utility)      
Current:      
Federal (26) 4 5
State (34) 94 (7)
Deferred:      
Federal 290 (2,363) (2,278)
State 185 (1,137) (1,009)
Tax credits (7) (5) (6)
Income tax provision (benefit) $ 408 $ (3,407) $ (3,295)
v3.20.4
INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Pacific Gas & Electric Co (Utility)    
Deferred income tax assets:    
Tax carryforwards $ 7,529 $ 1,308
Compensation 109 92
Wildfire-related claims 544 6,520
Operating lease liability 488 640
Other 219 121
Total deferred income tax assets 8,889 8,681
Deferred income tax liabilities:    
Property related basis differences 8,300 7,973
Regulatory balancing accounts 763 381
Debt financing costs 526 0
Operating lease right of use asset 488 640
Income tax regulatory asset 254 71
Other 128 58
Total deferred income tax liabilities 10,459 9,123
Total net deferred income tax liabilities 1,570 442
PG&E Corporation    
Deferred income tax assets:    
Tax carryforwards 7,641 1,390
Compensation 187 151
Wildfire-related claims 544 6,520
Operating lease liability 489 642
Other 212 112
Total deferred income tax assets 9,073 8,815
Deferred income tax liabilities:    
Property related basis differences 8,311 7,984
Regulatory balancing accounts 763 381
Debt financing costs 526 0
Operating lease right of use asset 489 642
Income tax regulatory asset 254 71
Other 128 57
Total deferred income tax liabilities 10,471 9,135
Total net deferred income tax liabilities $ 1,398 $ 320
v3.20.4
INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details)
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pacific Gas & Electric Co (Utility)      
Federal statutory income tax rate 21.00% 21.00% 21.00%
State income tax (net of federal benefit) 19.10% 7.50% 7.90%
Effect of regulatory treatment of fixed asset differences (44.90%) 2.80% 3.60%
Tax credits (1.70%) 0.10% 0.10%
Bankruptcy and emergence 54.10% 0.00% 0.00%
Other, net 2.20% (0.50%) 0.00%
Effective tax rate 49.80% 30.90% 32.60%
PG&E Corporation      
Federal statutory income tax rate 21.00% 21.00% 21.00%
State income tax (net of federal benefit) (15.30%) 7.50% 7.90%
Effect of regulatory treatment of fixed asset differences 39.00% 2.80% 3.60%
Tax credits 1.50% 0.10% 0.10%
Bankruptcy and emergence (82.50%) 0.00% 0.00%
Other, net (2.10%) (0.60%) (0.10%)
Effective tax rate (38.40%) 30.80% 32.50%
v3.20.4
INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pacific Gas & Electric Co (Utility)      
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]      
Balance, beginning of period $ 420 $ 377 $ 349
Reductions for tax position taken during a prior year (43) (1) (27)
Additions for tax position taken during the current year 60 44 55
Settlements 0 0 0
Expiration of statute 0 0 0
Balance, end of period 437 420 377
PG&E Corporation      
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]      
Balance, beginning of period 420 377 349
Reductions for tax position taken during a prior year (43) (1) (27)
Additions for tax position taken during the current year 60 44 55
Settlements 0 0 0
Expiration of statute 0 0 0
Balance, end of period $ 437 $ 420 $ 377
v3.20.4
INCOME TAXES (Narrative) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Income Tax Disclosure [Abstract]  
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year $ 16
v3.20.4
INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Federal  
Operating Loss Carryforwards [Line Items]  
Tax credit carryforward $ 134
Federal | Pre-2018  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 3,600
Federal | Post-2017  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 24,887
State  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 25,364
Tax credit carryforward $ 100
v3.20.4
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)
Dec. 31, 2020
MWh
MMBTU
Dec. 31, 2019
MMBTU
MWh
Forwards, Futures and Swaps | Natural Gas (MMBtus)    
Derivative [Line Items]    
Contract Volume 146,642,863 131,896,159
Forwards, Futures and Swaps | Electricity (Megawatt-hours)    
Derivative [Line Items]    
Contract Volume | MWh 9,435,830 18,675,852
Options | Natural Gas (MMBtus)    
Derivative [Line Items]    
Contract Volume 14,140,000 14,720,000
Options | Electricity (Megawatt-hours)    
Derivative [Line Items]    
Contract Volume 0 0
Congestion revenue rights | Electricity (Megawatt-hours)    
Derivative [Line Items]    
Contract Volume | MWh 266,091,470 308,467,999
v3.20.4
DERIVATIVES (Outstanding Derivative Balances) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance   $ 8
Netting $ (115)  
Netting 25 14
Commodity Contract | Pacific Gas & Electric Co (Utility)    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance (73) 5
Netting 0 0
Cash Collateral 140 6
Total Derivative Balance 67 11
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance 33 36
Netting 0 (6)
Cash Collateral 115 4
Total Derivative Balance 148 34
Commodity Contract | Pacific Gas & Electric Co (Utility) | Other noncurrent assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance 136 130
Netting 0 (6)
Cash Collateral 0 0
Total Derivative Balance 136 124
Commodity Contract | Pacific Gas & Electric Co (Utility) | Current liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance (38) (31)
Netting 0 6
Cash Collateral 15 2
Total Derivative Balance (23) (23)
Commodity Contract | Pacific Gas & Electric Co (Utility) | Noncurrent liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance (204) (130)
Netting 0 6
Cash Collateral 10 0
Total Derivative Balance $ (194) $ (124)
v3.20.4
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Short-term investments $ 470 $ 1,323
Total nuclear decommissioning trusts 4,209 3,703
Rabbi trusts 185 173
Long-term disability trust 167 166
Netting   (8)
Netting (115)  
Total assets 5,315 5,523
Netting (25) (14)
Amount primarily related to deferred taxes on appreciation of investment value 671 530
Electric    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting   (11)
Netting (2)  
Netting (25) (13)
Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Netting (113) (3)
Netting 0 (1)
Short-term investments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 27 6
Long-term disability trust 9 10
Global equity securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 2,398 2,086
Fixed-income securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 1,759 1,590
Rabbi trusts 106 100
Price risk management instruments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 284 158
TOTAL LIABILITIES 217 147
Price risk management instruments | Electric    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 170 152
TOTAL LIABILITIES 214 146
Price risk management instruments | Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 114 6
TOTAL LIABILITIES 3 1
Life insurance contracts    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Rabbi trusts 79 73
Level 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Short-term investments 470 1,323
Total nuclear decommissioning trusts 3,349 2,954
Rabbi trusts 0 0
Long-term disability trust 9 10
Total assets 3,828 4,287
Level 1 | Short-term investments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 27 6
Long-term disability trust 9 10
Level 1 | Global equity securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 2,398 2,086
Level 1 | Fixed-income securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 924 862
Rabbi trusts 0 0
Level 1 | Price risk management instruments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 0 0
TOTAL LIABILITIES 0 1
Level 1 | Price risk management instruments | Electric    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 0 0
TOTAL LIABILITIES 0 1
Level 1 | Price risk management instruments | Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 0 0
TOTAL LIABILITIES 0 0
Level 1 | Life insurance contracts    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Rabbi trusts 0 0
Level 2    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Short-term investments 0 0
Total nuclear decommissioning trusts 835 728
Rabbi trusts 185 173
Long-term disability trust 0 0
Total assets 1,023 906
Level 2 | Short-term investments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 0 0
Long-term disability trust 0 0
Level 2 | Global equity securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 0 0
Level 2 | Fixed-income securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 835 728
Rabbi trusts 106 100
Level 2 | Price risk management instruments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 3 5
TOTAL LIABILITIES 4 4
Level 2 | Price risk management instruments | Electric    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 2 2
TOTAL LIABILITIES 1 2
Level 2 | Price risk management instruments | Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 1 3
TOTAL LIABILITIES 3 2
Level 2 | Life insurance contracts    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Rabbi trusts 79 73
Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Short-term investments 0 0
Total nuclear decommissioning trusts 0 0
Rabbi trusts 0 0
Long-term disability trust 0 0
Total assets 166 161
Level 3 | Short-term investments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 0 0
Long-term disability trust 0 0
Level 3 | Global equity securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 0 0
Level 3 | Fixed-income securities    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 0 0
Rabbi trusts 0 0
Level 3 | Price risk management instruments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 166 161
TOTAL LIABILITIES 238 156
Level 3 | Price risk management instruments | Electric    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 166 161
TOTAL LIABILITIES 238 156
Level 3 | Price risk management instruments | Gas    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total price risk management instruments 0 0
TOTAL LIABILITIES 0 0
Level 3 | Life insurance contracts    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Rabbi trusts 0 0
Assets measured at NAV    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total nuclear decommissioning trusts 25 21
Long-term disability trust $ 158 $ 156
v3.20.4
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
$ / shares
Dec. 31, 2019
USD ($)
$ / shares
Market approach | Congestion revenue rights    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ $ 153 $ 140
Liabilities | $ 74 44
Discounted cash flow | Power purchase agreements    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ 13 21
Liabilities | $ $ 164 $ 112
CRR auction prices | Market approach | Congestion revenue rights | Minimum    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) (320.25) (20.20)
CRR auction prices | Market approach | Congestion revenue rights | Maximum    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) 320.25 20.20
CRR auction prices | Market approach | Congestion revenue rights | Weighted average price    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) 0.30 0.28
Forward prices | Discounted cash flow | Power purchase agreements | Minimum    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) 12.56 11.77
Forward prices | Discounted cash flow | Power purchase agreements | Maximum    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) 148.30 59.38
Forward prices | Discounted cash flow | Power purchase agreements | Weighted average price    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Range (in dollars per mwh) 35.52 33.62
v3.20.4
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Asset (liability) balance, beginning of period $ 5 $ 95
Included in regulatory assets and liabilities or balancing accounts (77) (90)
Asset (liability) balance, end of period $ (72) $ 5
v3.20.4
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Pacific Gas & Electric Co (Utility) | Pre-Petition Debt    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt instrument, face amount   $ 17,900
Carrying Amount    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument $ 1,901 0
Carrying Amount | Pacific Gas & Electric Co (Utility)    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 29,664 1,500
Level 2 | Estimate of Fair Value Measurement    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 2,175 0
Level 2 | Estimate of Fair Value Measurement | Pacific Gas & Electric Co (Utility)    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument $ 32,632 $ 1,500
v3.20.4
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost $ 2,180 $ 2,011
Total Unrealized Gains 2,033 1,698
Total Unrealized Losses (4) (6)
Total Fair Value 4,209 3,703
Amount primarily related to deferred taxes on appreciation of investment value 671 530
Short-term investments    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 27 6
Total Unrealized Gains 0 0
Total Unrealized Losses 0 0
Total Fair Value 27 6
Global equity securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 543 500
Total Unrealized Gains 1,881 1,609
Total Unrealized Losses (1) (2)
Total Fair Value 2,423 2,107
Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 1,610 1,505
Total Unrealized Gains 152 89
Total Unrealized Losses (3) (4)
Total Fair Value $ 1,759 $ 1,590
v3.20.4
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Debt Securities, Available-for-sale [Line Items]    
Total maturities of fixed-income securities $ 4,209 $ 3,703
Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Less than 1 year 50  
1–5 years 475  
5–10 years 403  
More than 10 years 831  
Total maturities of fixed-income securities $ 1,759 $ 1,590
v3.20.4
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Fair Value Disclosures [Abstract]      
Proceeds from sales and maturities of nuclear decommissioning investments $ 1,518 $ 956 $ 1,412
Gross realized gains on securities 159 69 54
Gross realized losses on securities $ (41) $ (14) $ (24)
v3.20.4
EMPLOYEE BENEFIT PLANS (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2020
USD ($)
noncallable_bond
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Defined Benefit Plan Disclosure [Line Items]      
Assumed health care cost trend rate 6.30%    
Ultimate trend rate 4.50%    
Assumed return 5.10%    
10 year actual rate of return 9.60%    
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond 835    
Total fair value of trust other net liabilities $ (249) $ 99  
Retirement savings plan expense $ 119 $ 109 $ 105
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
10 year actual rate of return 5.10% 5.70% 6.00%
Company contributions $ 343 $ 328  
Expected employer contribution next year 327    
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Company contributions 26 $ 29  
Expected employer contribution next year $ 15    
v3.20.4
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Funded Status:      
Noncurrent liability $ (2,444) $ (1,884)  
Pension Plan      
Change in plan assets:      
Fair value of plan assets at beginning of year 18,547 15,312  
Actual return on plan assets 2,736 3,713  
Company contributions 343 328  
Benefits and expenses paid (867) (806)  
Fair value of plan assets at end of year 20,759 18,547 $ 15,312
Change in benefit obligation:      
Benefit obligation at beginning of year 20,525 17,407  
Service cost for benefits earned 530 443 514
Interest cost 713 758 687
Actuarial loss 2,271 2,723  
Plan amendments 0 0  
Benefits and expenses paid (867) (806)  
Benefit obligation at end of year 23,172 20,525 17,407
Funded Status:      
Current liability (3) (14)  
Noncurrent liability (2,410) (1,964)  
Net (liability) asset at end of year (2,413) (1,978)  
Accumulated benefit obligation 20,700 18,400  
PBOP Plans      
Change in plan assets:      
Fair value of plan assets at beginning of year 2,678 2,258  
Actual return on plan assets 379 474  
Company contributions 26 29  
Plan participant contribution 81 82  
Benefits and expenses paid (169) (165)  
Fair value of plan assets at end of year 2,995 2,678 2,258
Change in benefit obligation:      
Benefit obligation at beginning of year 1,832 1,745  
Service cost for benefits earned 61 56 66
Interest cost 63 76 69
Actuarial loss (14) 22  
Benefits and expenses paid (149) (150)  
Federal subsidy on benefits paid 3 2  
Plan participant contributions 80 81  
Benefit obligation at end of year 1,876 1,832 $ 1,745
Funded Status:      
Noncurrent asset 1,153 879  
Noncurrent liability (34) (33)  
Net (liability) asset at end of year 1,119 846  
PBOP Plans | Postretirement Life Insurance Plan      
Change in plan assets:      
Fair value of plan assets at beginning of year 305    
Fair value of plan assets at end of year 343 305  
Change in benefit obligation:      
Benefit obligation at beginning of year 337    
Benefit obligation at end of year $ 377 $ 337  
v3.20.4
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Service cost for benefits earned $ 530 $ 443 $ 514
Interest cost 713 758 687
Expected return on plan assets (1,044) (906) (1,021)
Amortization of prior service cost (6) (6) (6)
Amortization of net actuarial loss 3 3 5
Net periodic benefit cost 196 292 179
Less: transfer to regulatory account 136 42 157
Total expense recognized 332 334 336
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Service cost for benefits earned 61 56 66
Interest cost 63 76 69
Expected return on plan assets (138) (123) (130)
Amortization of prior service cost 14 14 14
Amortization of net actuarial loss (21) (3) (5)
Net periodic benefit cost $ (21) $ 20 $ 14
v3.20.4
EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]      
Expected return on plan assets 9.60%    
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 2.77% 3.46% 4.35%
Rate of future compensation increases 3.80% 3.90% 3.90%
Expected return on plan assets 5.10% 5.70% 6.00%
Interest crediting rate for cash balance plan 1.95% 2.11% 3.15%
PBOP Plans | Minimum      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 2.67% 3.37% 4.29%
Expected return on plan assets 3.10% 3.50% 3.60%
PBOP Plans | Maximum      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 2.80% 3.47% 4.37%
Expected return on plan assets 6.10% 6.60% 6.80%
v3.20.4
EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2019
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   100.00% 100.00%
Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   30.00% 29.00%
Pension Plan | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   2.00% 5.00%
Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   8.00% 8.00%
Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   60.00% 58.00%
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   100.00% 100.00%
PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   28.00% 33.00%
PBOP Plans | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   2.00% 3.00%
PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   8.00% 6.00%
PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   62.00% 58.00%
Forecast | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 100.00%    
Forecast | Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 30.00%    
Forecast | Pension Plan | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 2.00%    
Forecast | Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 8.00%    
Forecast | Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 60.00%    
Forecast | PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 100.00%    
Forecast | PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 36.00%    
Forecast | PBOP Plans | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 1.00%    
Forecast | PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 5.00%    
Forecast | PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 58.00%    
v3.20.4
EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value $ 24,003 $ 21,324  
Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV 12 15 $ 8
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 20,993 18,636  
Assets measured at NAV 20,759 18,547 15,312
Pension Plan | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 742 844  
Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,875 1,650  
Pension Plan | Absolute Return      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2 1  
Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 517 549  
Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 9,633 8,655  
Pension Plan | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 5,194 5,038  
Pension Plan | Level 1 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 334 613  
Pension Plan | Level 1 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,875 1,650  
Pension Plan | Level 1 | Absolute Return      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1 0  
Pension Plan | Level 1 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 517 548  
Pension Plan | Level 1 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2,467 2,227  
Pension Plan | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 7,563 6,646  
Pension Plan | Level 2 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 408 231  
Pension Plan | Level 2 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 2 | Absolute Return      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1 1  
Pension Plan | Level 2 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 1  
Pension Plan | Level 2 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 7,154 6,413  
Pension Plan | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 12 15  
Pension Plan | Level 3 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Absolute Return      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 12 15  
Pension Plan | Assets measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV 8,224 6,937  
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 3,010 2,688  
Assets measured at NAV 2,995 2,678 $ 2,258
PBOP Plans | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 37 37  
PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 173 151  
PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 54 58  
PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,197 1,069  
PBOP Plans | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 745 439  
PBOP Plans | Level 1 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 37 37  
PBOP Plans | Level 1 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 173 151  
PBOP Plans | Level 1 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 54 58  
PBOP Plans | Level 1 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 481 193  
PBOP Plans | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 715 875  
PBOP Plans | Level 2 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 715 875  
PBOP Plans | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1 1  
PBOP Plans | Level 3 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1 1  
PBOP Plans | Assets measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV $ 1,549 $ 1,373  
v3.20.4
EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]    
Fair value of plan assets at beginning of year $ 15 $ 8
Actual return on plan assets:    
Relating to assets still held at the reporting date 2 0
Relating to assets sold during the period (3) 0
Purchases, issuances, sales, and settlements:    
Purchases 11 11
Settlements (13) (4)
Fair value of plan assets at end of year $ 12 $ 15
v3.20.4
EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Pension Plan  
Defined Benefit Plan Disclosure [Line Items]  
2021 $ 831
2022 913
2023 948
2024 980
2025 1,009
Thereafter in the succeeding five years 5,375
PBOP Plans  
Defined Benefit Plan Disclosure [Line Items]  
2021 85
2022 89
2023 92
2024 93
2025 95
Thereafter in the succeeding five years 471
Federal Subsidy  
Defined Benefit Plan Disclosure [Line Items]  
2021 (6)
2022 (6)
2023 (6)
2024 (7)
2025 (7)
Thereafter in the succeeding five years $ (41)
v3.20.4
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co (Utility) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Administrative services provided to PG&E Corporation      
Related Party Transaction [Line Items]      
Utility revenues from $ 3 $ 4 $ 4
Administrative services received from PG&E Corporation      
Related Party Transaction [Line Items]      
Utility expenses from 108 107 94
Utility employee benefit due to PG&E Corporation      
Related Party Transaction [Line Items]      
Utility expenses from $ 34 $ 42 $ 76
v3.20.4
RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - Pacific Gas & Electric Co (Utility) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Related Party Transaction [Line Items]    
Current receivables $ 35 $ 60
Current payables $ 46 $ 118
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Background) (Details) - Pacific Gas & Electric Co (Utility)
Nov. 08, 2018
a
fatality
building
Oct. 30, 2017
a
fatality
structure
wildfire
2018 Camp Fire    
Loss Contingencies [Line Items]    
Number of acres burned (acre) | a 153,336  
Number of fatalities (fatality) | fatality 85  
Number of other structures destroyed (structures) | building 18,804  
Northern California Wildfire    
Loss Contingencies [Line Items]    
Number of acres burned (acre) | a   245,000
Number of fatalities (fatality) | fatality   44
Number of wildfires (wildfire) | wildfire   21
Number of structures destroyed (structure) | structure   8,900
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date) (Details) - USD ($)
$ in Millions
 3 Months Ended 6 Months Ended
Jul. 01, 2020
Sep. 30, 2020
Jun. 30, 2020
Jan. 15, 2021
Dec. 31, 2020
Aug. 03, 2020
Jun. 12, 2020
Sep. 22, 2019
Loss Contingencies [Line Items]                
Transfer of shares to Fire Victim Trust (in shares) 477,000,000.0              
Transfer of shares to Fire Victim Trust, additional (in shares)           748,415    
Accrued environmental loss contingencies, current, elimination     $ 12,150.0          
Plan of reorganization, tax benefits payment agreement $ 1,350.0              
Subrogation claims, professional fees               $ 55.0
Subsequent Event                
Loss Contingencies [Line Items]                
Payment of plan of reorganization, tax benefits payment agreement       $ 758.0        
Settling Public Entities                
Loss Contingencies [Line Items]                
Litigation payment 1,000.0              
Litigation, segregated reimbursement fund 10.0              
Fire Victim Trust                
Loss Contingencies [Line Items]                
Litigation payment, fund, cash 5,400.0              
Litigation payment, additional funded, deferred $ 1,350.0              
Transfer of shares to Fire Victim Trust (in shares) 477,000,000              
Percentage of common stock owned, Fire Victim Trust if common issues additional shares 22.19%           22.19%  
Transfer of shares to Fire Victim Trust, additional (in shares)           748,415    
Subrogation Wildfire Trust                
Loss Contingencies [Line Items]                
Litigation payment, fund, cash $ 11,000.0              
Litigation payment 43.0              
Subrogation claims, professional fees $ 52.0              
Pacific Gas & Electric Co (Utility)                
Loss Contingencies [Line Items]                
Subrogation claims, professional fees         $ 53.0      
Subrogation insurance claims   $ 11,000.0            
Professional fees extinguished   47.5            
Pacific Gas & Electric Co (Utility) | All Other Wildfire-related Claims                
Loss Contingencies [Line Items]                
Wildfire-related claims     $ 13,500.0          
Pacific Gas & Electric Co (Utility) | Public Entity Wildfire Claims | Settling Public Entities                
Loss Contingencies [Line Items]                
Wildfire-related claims   $ 1,000.0            
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Plan Support Agreements with Public Entities) (Details) - Public Entity Wildfire Claims - Settled Litigation
$ in Millions
Jun. 18, 2019
USD ($)
Loss Contingencies [Line Items]  
Settlement reached $ 1,000
Fund to support defense or resolution of claims per plan support agreement $ 10
v3.20.4
WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details)
$ in Millions
Jul. 01, 2020
USD ($)
Sep. 22, 2019
USD ($)
Dec. 31, 2020
USD ($)
Jun. 12, 2020
Dec. 06, 2019
USD ($)
Loss Contingencies [Line Items]          
TCC claims settlement, amount $ 11,000 $ 11,000      
Subrogation claims, professional fees   $ 55      
Fire Victim Trust          
Loss Contingencies [Line Items]          
Percentage of common stock owned, Fire Victim Trust if common issues additional shares 22.19%     22.19%  
Pacific Gas & Electric Co (Utility)          
Loss Contingencies [Line Items]          
Subrogation claims, professional fees     $ 53    
Cash         $ 1,350
Multiplier, normalized estimated net income         14.9
Number of fully diluted shares of the reorganized, percentage         20.90%
Pacific Gas & Electric Co (Utility) | Effective Date          
Loss Contingencies [Line Items]          
Cash contribution by company         $ 5,400
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2021          
Loss Contingencies [Line Items]          
Cash         758
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2022          
Loss Contingencies [Line Items]          
Cash         $ 592
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire and 2020 Zogg Fire) (Details)
$ in Millions
 12 Months Ended
Nov. 04, 2019
numberOfPeople
Dec. 31, 2020
USD ($)
Feb. 24, 2021
numberOfPlaintiff
plaintiff
complaint
Sep. 27, 2020
a
structure
fatality
injury
Dec. 31, 2019
USD ($)
Oct. 23, 2019
a
structure
injury
customer
numberOfFatality
Loss Contingencies [Line Items]            
Cumulative reimbursements from insurance policies   $ 649.0        
Insurance receivable   674.0     $ 2,238.0  
2019 Kincade Fire            
Loss Contingencies [Line Items]            
Number of acres burned (acre) | a           77,758
Number of fatalities (fatality) | numberOfFatality           0
Number of injuries | injury           4
Number of structures destroyed (structure) | structure           374
Number of residences destroyed (residence) | structure           174
Number of commercial structures destroyed (structure) | structure           11
Number of other structures destroyed (structures) | structure           189
Number of structures damaged (structure) | structure           60
Number of residential structures damaged (structure) | structure           35
Number of commercial structures damaged (structure) | structure           1
Number of other structures damaged (structure) | structure           24
Number of people part of mandatory evacuation order | numberOfPeople 200,000          
Number of customers without power | customer           27,837
Potential loss contingency   625.0        
Loss contingency, claim eligibility requirement amount   1,000.0        
Cumulative reimbursements from insurance policies   430.0        
Insurance receivable   430.0     0.0  
2019 Kincade Fire | Subsequent Event            
Loss Contingencies [Line Items]            
Number of complaint | complaint     22      
Number of plaintiffs represented by complaints | plaintiff     504      
2020 Zogg Fire            
Loss Contingencies [Line Items]            
Number of acres burned (acre) | a       56,338    
Number of fatalities (fatality) | fatality       4    
Number of injuries | injury       1    
Number of structures destroyed (structure) | structure       204    
Number of structures damaged (structure) | structure       27    
Potential loss contingency   275.0        
Loss contingency, claim eligibility requirement amount   1,000.0        
Cumulative reimbursements from insurance policies   219.0        
Number of single family homes destroyed | structure       63    
Insurance receivable   219.0     $ 0.0  
Initial self-insured retention per occurrence   60.0        
Legal fees   4.0        
2020 Zogg Fire | Maximum            
Loss Contingencies [Line Items]            
Cumulative reimbursements from insurance policies   $ 867.5        
2020 Zogg Fire | Subsequent Event            
Loss Contingencies [Line Items]            
Number of complaint | complaint     6      
Number of plaintiffs represented by complaints | numberOfPlaintiff     240      
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($)
$ in Millions
 12 Months Ended
Jul. 01, 2020
Dec. 31, 2020
Jul. 31, 2020
Dec. 31, 2019
Loss Contingencies [Line Items]        
Prepaid insurance   $ 536.0    
Insurance premium costs, recovery, coverage amount   1,400.0    
Insurance receivable   674.0   $ 2,238.0
Insurance Coverage For Wildfire and Non-Wildfire Events        
Loss Contingencies [Line Items]        
Costs for insurance coverage $ 859.0      
Insurance Coverage For Wildfire and Non-Wildfire Events | August 1, 2019 through July 31, 2020        
Loss Contingencies [Line Items]        
Costs for insurance coverage   212.0    
Insurance Coverage for Wildfire Events        
Loss Contingencies [Line Items]        
Liability insurance coverage     $ 867.5  
Initial self-insured retention per occurrence     60.0  
Insurance Coverage for Wildfire Events | August 1, 2019 through July 31, 2020        
Loss Contingencies [Line Items]        
Liability insurance coverage   430.0    
Initial self-insured retention per occurrence   10.0    
Insurance Coverage for Wildfire Events | August 1, 2019 through September 2, 2020        
Loss Contingencies [Line Items]        
Liability insurance coverage     825.0  
Insurance Coverage for Wildfire Events | July 1, 2020 - June 30, 2021        
Loss Contingencies [Line Items]        
Reinsurance     42.5  
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2019 through July 31, 2020        
Loss Contingencies [Line Items]        
Liability insurance coverage   520.0    
Initial self-insured retention per occurrence   10.0    
Insurance Coverage For Non-Wildfire Liabilities | September 3, 2019 through September 2, 2020        
Loss Contingencies [Line Items]        
Liability insurance coverage   480.0    
Insurance Coverage For Non-Wildfire Liabilities | August 1, 2020 - July 31, 2021        
Loss Contingencies [Line Items]        
Liability insurance coverage     700.0  
Initial self-insured retention per occurrence     $ 10.0  
2019 Kincade Fire        
Loss Contingencies [Line Items]        
Insurance receivable   430.0   0.0
2020 Zogg Fire        
Loss Contingencies [Line Items]        
Initial self-insured retention per occurrence   60.0    
Insurance receivable   219.0   0.0
2017 Northern California wildfires        
Loss Contingencies [Line Items]        
Insurance receivable   25.0   $ 808.0
Estimated insurance recoveries, pending to receive   $ 25.0    
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2020
USD ($)
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance $ 2,238
Accrued insurance recoveries 649
Reimbursements (2,213)
Insurance Receivable, Ending Balance 674
2020 Zogg Fire  
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance 0
Accrued insurance recoveries 219
Reimbursements 0
Insurance Receivable, Ending Balance 219
2019 Kincade Fire  
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance 0
Accrued insurance recoveries 430
Reimbursements 0
Insurance Receivable, Ending Balance 430
2018 Camp Fire  
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance 1,380
Accrued insurance recoveries 0
Reimbursements (1,380)
Insurance Receivable, Ending Balance 0
2017 Northern California wildfires  
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance 808
Accrued insurance recoveries 0
Reimbursements (783)
Insurance Receivable, Ending Balance 25
2015 Butte Fire  
Insurance Receivable [Roll Forward]  
Insurance Receivable, Beginning Balance 50
Accrued insurance recoveries 0
Reimbursements (50)
Insurance Receivable, Ending Balance $ 0
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2018 Camp Fire and 2017 Northern California Wildfires - USD ($)
$ in Millions
Apr. 30, 2020
Jul. 08, 2019
Loss Contingencies [Line Items]    
Customer Harm Threshold, potential regulatory adjustment, percentage   20.00%
Customer Harm Threshold, Potential regulatory adjustment, percentage of total disallowed wildlife liability   5.00%
Customer Harm Threshold, post-emergence transaction, securitized $ 7,500  
Customer Harm Threshold, post-emergence transaction, debt retirement 6,000  
Customer Harm Threshold, post-emergence transaction, debt payment acceleration $ 592  
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties
Feb. 24, 2021
notice
Nov. 20, 2017
lawsuit
Nov. 16, 2017
lawsuit
Subsequent Event      
Loss Contingencies [Line Items]      
Number of causes of action (causes) | notice 2    
Derivative Lawsuits Filed in the San Francisco County Superior Court      
Loss Contingencies [Line Items]      
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit   2 2
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation and Debt Claims) (Details)
Dec. 31, 2020
lawsuit
Feb. 22, 2019
offering
Jun. 30, 2018
lawsuit
Wildfire-Related Class Action      
Loss Contingencies [Line Items]      
Number of lawsuits filed against company (lawsuit, complaint)     2
Number of public offerings of notes with complaints against underwriters (offering) | offering   4  
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt      
Loss Contingencies [Line Items]      
Number of lawsuits filed against company (lawsuit, complaint) 3    
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (De-energization Class Action) (Details) - De-energization Class Action - Subsequent Event
$ in Millions
Feb. 16, 2021
USD ($)
Loss Contingencies [Line Items]  
Litigation settlement, amount awarded from other party $ 10
Litigation settlement, approval of settlement, escrow deposit, number of days 14 days
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details)
$ in Millions
 12 Months Ended
Jul. 21, 2020
USD ($)
Mar. 17, 2020
USD ($)
count
Dec. 31, 2020
USD ($)
Dec. 31, 2019
USD ($)
Dec. 31, 2018
USD ($)
Loss Contingencies [Line Items]          
Wildfire fund expense     $ 413.0 $ 0.0 $ 0.0
Pacific Gas & Electric Co (Utility)          
Loss Contingencies [Line Items]          
Wildfire fund expense     $ 413.0 $ 0.0 $ 0.0
Pacific Gas & Electric Co (Utility) | Complaints Brought By Butte County District Attorney | Loss from Wildfires          
Loss Contingencies [Line Items]          
Number of guilty involuntary manslaughter pleas | count   84      
Wildfire fund expense $ 3.5 $ 3.5      
Reimbursement of investigation fees $ 0.5 0.5      
Committed funds for impacted residence   $ 15.0      
Committed funds for impacted residence, minimum term   5 years      
v3.20.4
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($)
$ in Millions
Jan. 14, 2021
Aug. 23, 2019
Dec. 31, 2020
Jul. 01, 2020
Jul. 12, 2019
Loss Contingencies [Line Items]          
Disallowance cap, transmission and distribution equity rate base         $ 2,700
Initial safety certification, period   12 months      
Initial safety certification, documentation provided, period   90 days      
Expected capitalization, proceeds of bond     $ 10,500    
Expected capitalization, initial contribution     7,500    
Expected capitalization, annual contribution     300    
Expected wildfire fund allocation metric, percentage         64.20%
Expected wildfire fund allocation metric, initial contribution         $ 4,800
Expected wildfire fund allocation metric, annual contributions         193
Allocation         $ 3,210
Initial contribution payment       $ 4,800  
Annual contribution, first payment       $ 193  
Annual contribution, second payment     $ 193    
Subsequent Event          
Loss Contingencies [Line Items]          
Initial safety certification, valid period 12 months        
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Narrative) (Details)
$ in Millions
Jan. 04, 2021
party
Dec. 31, 2021
USD ($)
Dec. 31, 2020
USD ($)
Jun. 08, 2020
party
Apr. 20, 2020
USD ($)
Dec. 17, 2019
USD ($)
Loss Contingencies [Line Items]            
Expenses and capital expenditures, disallowed costs     $ 1,625      
Expenses and capital expenditures, disallowed capital, approved         $ 198  
Shareholder-funded system enhancement initiatives, approved         64  
Fine payable to general fund, suspended         200  
Number of parties filed separate applications for rehearing | party       2    
Wildfire mitigation plan memorandum account            
Loss Contingencies [Line Items]            
Expenses and capital expenditures, disallowed capital, approved         $ 198  
Subsequent Event            
Loss Contingencies [Line Items]            
Number of parties filed petition for review of the CUPC decision | party 1          
Pacific Gas & Electric Co (Utility)            
Loss Contingencies [Line Items]            
Expenses and capital expenditures     1,625      
Pacific Gas & Electric Co (Utility) | Wildfire mitigation plan memorandum account            
Loss Contingencies [Line Items]            
Expenses and capital expenditures, charges recorded     $ 152      
Pacific Gas & Electric Co (Utility) | Forecast | Wildfire mitigation plan memorandum account            
Loss Contingencies [Line Items]            
Expenses and capital expenditures, charges recorded   $ 46        
Pacific Gas & Electric Co (Utility) | Pending Litigation | Unfavorable Regulatory Action            
Loss Contingencies [Line Items]            
Expenses and capital expenditures           $ 1,625
Shareholder-funded system enhancement initiatives, amount           $ 50
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Legal Obligation) (Details) - Pacific Gas & Electric Co (Utility)
$ in Millions
Dec. 31, 2020
USD ($)
Loss Contingencies [Line Items]  
Expense $ 1,222
Capital 403
Total 1,625
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)  
Loss Contingencies [Line Items]  
Expense 236
Capital 0
Total 236
Transmission Safety Inspections and Repairs Expense (TO)  
Loss Contingencies [Line Items]  
Expense 433
Capital 0
Total 433
Vegetation Management Support Costs (FHPMA)  
Loss Contingencies [Line Items]  
Expense 36
Capital 0
Total 36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)  
Loss Contingencies [Line Items]  
Expense 82
Capital 66
Total 148
2018 Camp Fire CEMA Expense (CEMA)  
Loss Contingencies [Line Items]  
Expense 435
Capital 0
Total 435
2018 Camp Fire CEMA Capital for Restoration (CEMA)  
Loss Contingencies [Line Items]  
Expense 0
Capital 253
Total 253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)  
Loss Contingencies [Line Items]  
Expense 0
Capital 84
Total $ 84
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details)
Sep. 21, 2018
May 21, 2020
Loss Contingencies [Line Items]    
Approved depreciation rate   2.94%
Requested depreciation rate   3.25%
Labor rates, allocation percentage   6.15%
Direct assignment, percentage   8.84%
Pacific Gas & Electric Co (Utility) | Electric    
Loss Contingencies [Line Items]    
Requested revenue rate 98.85%  
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]    
Accrued legal liabilities $ 144 $ 116
v3.20.4
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
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (GT&S Capital Expenditures 2011-2014 and CZU Lightning Complex Fire Notice of Violations) (Details)
$ in Millions
 1 Months Ended
Jun. 23, 2016
USD ($)
Feb. 08, 2021
notice
Jul. 31, 2020
USD ($)
Disallowance of Plant Costs      
Loss Contingencies [Line Items]      
Gas transmission and storage capital disallowance $ 696    
Permanently disallowed capital 120    
Amount subject to audit $ 576    
Capital expenditures for future recovery     $ 512
CZU Lightning Complex Fire Notice of Violations | Subsequent Event      
Loss Contingencies [Line Items]      
Number of notices issued of violation | notice   5  
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]    
Topock natural gas compressor station $ 303 $ 362
Hinkley natural gas compressor station 132 138
Former manufactured gas plant sites owned by the Utility or third parties 659 568
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 111 101
Fossil fuel-fired generation facilities and sites 96 106
Total environmental remediation liability $ 1,301 $ 1,275
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Long-term Purchase Commitment [Line Items]  
Amount of environmental loss accrual expected to be recovered $ 986
Topock Site  
Long-term Purchase Commitment [Line Items]  
Utility undiscounted future costs $ 216
Topock Site | Pacific Gas & Electric Co (Utility)  
Long-term Purchase Commitment [Line Items]  
Remediation cost recovery percentage 90.00%
Hinkley Natural Gas Compressor Station  
Long-term Purchase Commitment [Line Items]  
Utility undiscounted future costs $ 138
Former Manufactured Gas Plant  
Long-term Purchase Commitment [Line Items]  
Utility undiscounted future costs $ 460
Former Manufactured Gas Plant | Pacific Gas & Electric Co (Utility)  
Long-term Purchase Commitment [Line Items]  
Remediation cost recovery percentage 90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites  
Long-term Purchase Commitment [Line Items]  
Utility undiscounted future costs $ 67
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co (Utility)  
Long-term Purchase Commitment [Line Items]  
Remediation cost recovery percentage 90.00%
Fossil Fuel Fired Generation  
Long-term Purchase Commitment [Line Items]  
Utility undiscounted future costs $ 43
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details)
$ in Millions
 8 Months Ended 12 Months Ended
Feb. 24, 2021
outage
Dec. 31, 2020
USD ($)
nuclear_generating_unit
Long-term Purchase Commitment [Line Items]    
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit   2
Maximum total payment incurred per event under the loss sharing program   $ 450
Humboldt Bay Unit    
Long-term Purchase Commitment [Line Items]    
Amount of property damage coverage provided by NEIL   50
Amount of liability insurance for Humboldt Bay Unit 3   53
Diablo Canyon    
Long-term Purchase Commitment [Line Items]    
Maximum public liability per nuclear incident under Price-Anderson Act   13,800
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act   450
Maximum annual payment incurred per event under the loss sharing program   275
Coverage for purchased public liability insurance, per incident   $ 41
Period for inflation adjustment   5 years
Diablo Canyon | Subsequent Event    
Long-term Purchase Commitment [Line Items]    
Number of outages experienced | outage 4  
Nuclear Incident    
Long-term Purchase Commitment [Line Items]    
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon   $ 3,200
Nuclear Incident | Humboldt Bay Unit    
Long-term Purchase Commitment [Line Items]    
Amount of indemnification from the nuclear regulatory commission for public liability arising from nuclear incidents   500
Non-Nuclear Incident    
Long-term Purchase Commitment [Line Items]    
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon   2,700
European Mutual Association for Nuclear Insurance    
Long-term Purchase Commitment [Line Items]    
Full insurance policy limit   200
Potential premium obligation   4
Nuclear Electric Insurance Limited    
Long-term Purchase Commitment [Line Items]    
Potential premium obligation   $ 43
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Long-term Purchase Commitment [Line Items]  
2021 $ 3,447
2022 2,860
2023 2,488
2024 2,303
2025 2,244
Thereafter 21,841
Total purchase commitments 35,183
Renewable Energy  
Long-term Purchase Commitment [Line Items]  
2021 2,270
2022 2,042
2023 1,997
2024 1,972
2025 1,962
Thereafter 21,335
Total purchase commitments 31,578
Conventional Energy  
Long-term Purchase Commitment [Line Items]  
2021 582
2022 511
2023 223
2024 72
2025 70
Thereafter 281
Total purchase commitments 1,739
Other  
Long-term Purchase Commitment [Line Items]  
2021 65
2022 62
2023 61
2024 61
2025 61
Thereafter 41
Total purchase commitments 351
Natural Gas  
Long-term Purchase Commitment [Line Items]  
2021 466
2022 191
2023 158
2024 151
2025 151
Thereafter 184
Total purchase commitments 1,301
Nuclear Fuel  
Long-term Purchase Commitment [Line Items]  
2021 64
2022 54
2023 49
2024 47
2025 0
Thereafter 0
Total purchase commitments $ 214
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Power Purchases and Electric Capacity      
Third-Party Power Purchase Agreements [Line Items]      
Costs incurred for power purchases and electric capacity $ 2,900 $ 3,000 $ 3,100
Nuclear Fuel      
Third-Party Power Purchase Agreements [Line Items]      
Payments for nuclear fuel 111 74 73
Gas Contracts      
Third-Party Power Purchase Agreements [Line Items]      
Cost of goods $ 800 $ 900 $ 600
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details)
$ in Millions
Dec. 31, 2020
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
2021 $ 40
2022 30
2023 46
2024 65
2025 60
Thereafter 2,924
Total minimum lease payments $ 3,165
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]      
Payments for other commitments $ 45 $ 48 $ 43
Operating Leased Assets [Line Items]      
Present value of fixed capacity payments, portion classified as current liabilities 533 556  
Present value of fixed capacity payments, portion classified as noncurrent liabilities 1,208 1,730  
Qualifying Facilities      
Operating Leased Assets [Line Items]      
Capitalized asset for fixed capacity payments for corresponding assets 7 9  
Capitalized asset for fixed capacity payments, accumulated amortization 11 9  
Present value of fixed capacity payments, portion classified as current liabilities 2 2  
Present value of fixed capacity payments, portion classified as noncurrent liabilities $ 5 $ 7  
Minimum      
Operating Leased Assets [Line Items]      
Extension option for operating leases 1 year    
Maximum      
Operating Leased Assets [Line Items]      
Extension option for operating leases 5 years    
v3.20.4
OTHER CONTINGENCIES AND COMMITMENTS (Oakland Headquarters Lease) (Details)
ft² in Thousands, $ in Millions
Oct. 23, 2020
USD ($)
Jun. 05, 2020
USD ($)
ft²
Commitments and Contingencies Disclosure [Abstract]    
Rentable square feet | ft²   910
Lease, option payment letter of credit $ 75  
Lease, security letter of credit $ 75  
Term of contract   34 years 11 months
Purchase options, land, value   $ 892
v3.20.4
SUBSEQUENT EVENTS (Details) - Pacific Gas & Electric Co (Utility) - Subsequent Event - SBA Communications Corporation - Wireless Licenses
$ in Millions
Feb. 16, 2021
USD ($)
transmissionTower
Subsequent Event [Line Items]  
Duration of contract 100 years
Proceeds from sale of transmission tower license $ 973
Proceeds from sale of transmission tower license, closing 954
Proceeds from sale of transmission tower license, initial cash proceeds $ 945
Other tower, duration of contract 15 years
Minimum | Effective Date Towers  
Subsequent Event [Line Items]  
Number of electric transmission towers | transmissionTower 700
Number of other electric transmission towers | transmissionTower 28,000
v3.20.4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Operating expenses $ (16,714) $ (27,223) $ (26,459)
Interest income 39 82 76
Interest expense (1,260) (934) (929)
Other income, net 483 250 424
Reorganization items, net (1,959) (346) 0
Loss Before Income Taxes (942) (11,042) (10,129)
Income tax provision (benefit) 362 (3,400) (3,292)
Loss Attributable to Common Shareholders (1,318) (7,656) (6,851)
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (17) (1) 4
Total other comprehensive income (loss) $ (17) $ (1) $ 4
Weighted Average Common Shares Outstanding, Basic (in shares) 1,257 528 517
Weighted Average Common Shares Outstanding, Diluted (in shares) 1,257 528 517
Net Loss Per Common Share, Basic (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Net Loss Per Common Share, Diluted (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Pension and other postretirement benefit plans obligations, tax $ 7 $ 0 $ 2
PG&E Corporation      
Operating expenses (103) (114) (91)
Interest income 0 1 2
Interest expense (149) (21) (15)
Other income, net 13 10 (2)
Reorganization items, net (1,649) (26) 0
Equity in earnings of subsidiaries 411 (7,622) (6,832)
Loss Before Income Taxes (1,350) (7,634) (6,848)
Income tax provision (benefit) (46) 8 3
Loss Attributable to Common Shareholders (1,304) (7,642) (6,851)
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (17) (1) 4
Total other comprehensive income (loss) (17) (1) 4
Comprehensive Loss $ (1,321) $ (7,643) $ (6,847)
Weighted Average Common Shares Outstanding, Basic (in shares) 1,257 528 517
Weighted Average Common Shares Outstanding, Diluted (in shares) 1,257 528 513
Net Loss Per Common Share, Basic (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Net Loss Per Common Share, Diluted (in dollars per share) $ (1.05) $ (14.50) $ (13.25)
Pension and other postretirement benefit plans obligations, tax $ 7 $ 0 $ 2
PG&E Corporation | Administrative service revenue      
Revenue $ 127 $ 138 $ 90
v3.20.4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($)
$ in Millions
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Current Assets      
Cash and cash equivalents $ 484 $ 1,570 $ 1,668
Other 1,334 639  
Total current assets 9,602 10,165  
Noncurrent Assets      
Equipment 93,894 88,090  
Accumulated depreciation (27,758) (26,455)  
Net property, plant, and equipment 66,136 61,635  
Operating lease right of use asset 1,741 2,286  
TOTAL ASSETS 97,856 85,196  
Current Liabilities      
Long-term debt, classified as current 28 0  
Operating lease liabilities 533 556  
Other current liabilities 2,256 1,254  
Total current liabilities 13,581 7,631  
Noncurrent Liabilities      
Debtor-in-possession financing 37,288 0  
Operating lease liabilities 1,208 1,730  
Other 3,848 2,573  
Total noncurrent liabilities 63,022 21,631  
Liabilities Subject to Compromise 0 50,546  
Common Shareholders’ Equity      
Common stock, no par value 30,224 13,038  
Reinvested earnings (9,196) (7,892)  
Accumulated other comprehensive income (loss) (27) (10)  
Total shareholders' equity 21,001 5,136  
TOTAL LIABILITIES AND EQUITY 97,856 85,196  
PG&E Corporation      
Current Assets      
Cash and cash equivalents 223 448  
Advances to affiliates 48 120  
Income taxes receivable 12 12  
Other 13 11  
Total current assets 296 591  
Noncurrent Assets      
Equipment 2 2  
Accumulated depreciation (2) (2)  
Net property, plant, and equipment 0 0  
Investments in subsidiaries 25,244 5,102  
Other investments 186 173  
Operating lease right of use asset 3 6  
Deferred income taxes 237 187  
Total noncurrent assets 25,670 5,468  
TOTAL ASSETS 25,966 6,059  
Current Liabilities      
Long-term debt, classified as current 28 0  
Accounts payable – other 49 47  
Operating lease liabilities 3 3  
Other current liabilities 72 3  
Total current liabilities 152 53  
Noncurrent Liabilities      
Debtor-in-possession financing 4,624 0  
Operating lease liabilities 0 3  
Other 191 58  
Total noncurrent liabilities 4,815 61  
Liabilities Subject to Compromise 0 810  
Common Shareholders’ Equity      
Common stock, no par value 30,224 13,038  
Reinvested earnings (9,198) (7,893)  
Accumulated other comprehensive income (loss) (27) (10)  
Total shareholders' equity 20,999 5,135  
TOTAL LIABILITIES AND EQUITY $ 25,966 $ 6,059  
v3.20.4
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Jul. 01, 2020
Jun. 25, 2020
Jul. 31, 2020
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
Cash Flows from Operating Activities            
Net Loss       $ (1,304) $ (7,642) $ (6,837)
Adjustments to reconcile net income to net cash provided by operating activities:            
Deferred income taxes and tax credits, net       1,097 (2,948) (2,532)
Reorganization items, net       1,458 108 0
Liabilities subject to compromise       413 12,222 0
Net cash provided by (used in) operating activities       (19,130) 4,816 4,752
Cash Flows from Investing Activities            
Net cash used in investing activities       (7,748) (6,378) (6,564)
Cash Flows From Financing Activities:            
Debtor-in-possession credit facility debt issuance costs       (6) (113) 0
Bridge facility financing fees       (73) 0 0
Borrowings under credit facilities       8,554 0 3,960
Repayments under credit facilities       (3,949) 0 (775)
Net repayments of commercial paper       0 0 (182)
Repayment of long-term debt       (764) 0 (795)
Equity Units issued $ 9,000 $ 3,970 $ 9,000 1,304 0 0
Net cash provided by financing activities       25,928 1,464 3,031
Net change in cash, cash equivalents, and restricted cash       (950) (98) 1,219
Cash, cash equivalents, and restricted cash at January 1       1,577 1,675 456
Cash, cash equivalents, and restricted cash at December 31       627 1,577 1,675
Cash paid for:            
Interest, net of amounts capitalized       (1,563) (10) (786)
Income taxes, net       0 0 (49)
Supplemental disclosures of noncash investing and financing activities            
Operating lease liabilities arising from obtaining ROU assets       13 2,816 0
Common stock issued in satisfaction of liabilities       8,276 0 0
PG&E Corporation            
Cash Flows from Operating Activities            
Net Loss       (1,304) (7,642) (6,851)
Adjustments to reconcile net income to net cash provided by operating activities:            
Stock-based compensation amortization       28 43 78
Equity in earnings of subsidiaries       (412) 7,622 6,833
Deferred income taxes and tax credits, net       (50) 0 (62)
Reorganization items, net       1,548 11 0
Current income taxes receivable/payable       0 6 9
Liabilities subject to compromise       12 28 0
Other       97 (62) 41
Net cash provided by (used in) operating activities       (81) 6 48
Cash Flows from Investing Activities            
Investment in subsidiaries       (12,986) 0 (45)
Net cash used in investing activities       (12,986) 0 (45)
Cash Flows From Financing Activities:            
Debtor-in-possession credit facility debt issuance costs       0 (16) 0
Bridge facility financing fees       (40) 0 0
Borrowings under credit facilities       0 0 425
Repayments under credit facilities       0 0 (125)
Net repayments of commercial paper       0 0 (132)
Short-term debt financing       0 0 350
Proceeds from issuance of long-term debt       4,660 0 0
Repayment of long-term debt       (664) 0 (350)
Common stock issued       7,582 85 200
Equity Units issued       1,304 0 0
Net cash provided by financing activities       12,842 69 368
Net change in cash, cash equivalents, and restricted cash       (225) 75 371
Cash, cash equivalents, and restricted cash at January 1       448 373 2
Cash, cash equivalents, and restricted cash at December 31       223 448 373
Cash paid for:            
Interest, net of amounts capitalized       (105) (3) (13)
Income taxes, net       0 0 10
Supplemental disclosures of noncash investing and financing activities            
Operating lease liabilities arising from obtaining ROU assets       0 9 0
Common stock issued in satisfaction of liabilities       $ 8,276 $ 0 $ 0
v3.20.4
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2018
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Beginning of Period $ 43 $ 56 $ 64
Charged to Costs and Expenses 138 0 34
Charged to Other Accounts 0 0 0
Deductions 35 13 42
Balance at End of Period $ 146 $ 43 $ 56