PACIFIC GAS & ELECTRIC CO, 10-Q filed on 4/23/2026
Quarterly Report
v3.26.1
Cover Page - shares
 3 Months Ended
Mar. 31, 2026
Apr. 15, 2026
Document Type 10-Q  
Document Quarterly Report true  
Document Period End Date Mar. 31, 2026  
Document Transition Report false  
Entity File Number 1-12609  
Entity Incorporation, State or Country Code CA  
Entity Tax Identification Number 94-3234914  
Entity Address, Address Line One 300 Lakeside Drive  
Entity Address, City or Town Oakland,  
Entity Address, State or Province CA  
Entity Address, Postal Zip Code 94612  
City Area Code 415  
Local Phone Number 973-1000  
Entity Current Reporting Status Yes  
Entity Interactive Data Current Yes  
Entity Filer Category Large Accelerated Filer  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Shell Company false  
Entity Bankruptcy Proceedings, Reporting Current true  
Entity Common Stock, Shares Outstanding (in shares)   2,679,968,318
Amendment Flag false  
Document Fiscal Year Focus 2026  
Document Fiscal Period Focus Q1  
Entity Registrant Name PG&E CORP  
Entity Central Index Key 0001004980  
Current Fiscal Year End Date --12-31  
Utility    
Entity File Number 1-2348  
Entity Incorporation, State or Country Code CA  
Entity Tax Identification Number 94-0742640  
Entity Address, Address Line One 300 Lakeside Drive  
Entity Address, City or Town Oakland,  
Entity Address, State or Province CA  
Entity Address, Postal Zip Code 94612  
City Area Code 415  
Local Phone Number 973-7000  
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  
Entity Shell Company false  
Entity Bankruptcy Proceedings, Reporting Current true  
Entity Common Stock, Shares Outstanding (in shares)   264,374,809
Amendment Flag false  
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 | 6.000% Series A Mandatory Convertible Preferred Stock, no par value    
Title of 12(b) Security 6.000% Series A Mandatory Convertible Preferred Stock, no par value  
Trading Symbol PCG-PrX  
Security Exchange Name NYSE  
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  
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, 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, 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 $25 per share, 4.36% redeemable  
Trading Symbol PCG-PI  
Security Exchange Name NYSEAMER  
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Operating Revenues    
Total operating revenues $ 6,881 $ 5,983
Operating Expenses    
Operating and maintenance 3,112 2,646
Wildfire-related claims, net of recoveries 0 49
Wildfire Fund expense 102 76
Depreciation, amortization, and decommissioning 1,166 1,097
Total operating expenses 5,411 4,763
Operating Income 1,470 1,220
Interest income 122 117
Interest expense (803) (734)
Other income, net 116 70
Income Before Income Taxes 905 673
Income tax provision 20 39
Net Income 885 634
Preferred stock dividend requirement 27 27
Income Available for Common Shareholders 858 607
Income Available for Common Shareholders $ 858 $ 607
Weighted Average Common Shares Outstanding, Basic (in shares) 2,199 2,195
Weighted Average Common Shares Outstanding, Diluted (in shares) 2,281 2,200
Net Income Per Common Share, Basic (in dollars per share) $ 0.39 $ 0.28
Net Income Per Common Share, Diluted (in dollars per share) $ 0.39 $ 0.28
Electric    
Operating Revenues    
Total operating revenues $ 4,967 $ 4,135
Operating Expenses    
Cost of electricity and natural gas 561 399
Natural gas    
Operating Revenues    
Total operating revenues 1,914 1,848
Operating Expenses    
Cost of electricity and natural gas $ 470 $ 496
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Statement of Comprehensive Income [Abstract]    
Net Income $ 885 $ 634
Other Comprehensive Income    
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3 and $2, respectively) (6) 7
Total other comprehensive income (loss) (6) 7
Comprehensive Income 879 641
Preferred stock dividend requirement 27 27
Comprehensive Income Available for Common Shareholders $ 852 $ 614
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Statement of Comprehensive Income [Abstract]    
Net unrealized gain (losses) on available for sale securities, tax $ 3 $ 2
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Current Assets    
Cash and cash equivalents $ 1,131 $ 713
Restricted cash and restricted cash equivalents (includes $325 million and $225 million related to VIEs at respective dates) 359 259
Accounts receivable    
Customers (net of allowance for doubtful accounts of $407 million and $408 million at respective dates) (includes $1.6 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $407 million and $408 million at respective dates) 1,928 2,267
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,436 1,463
Regulatory balancing accounts 5,025 6,300
Other (net of allowance for doubtful accounts of $72 million and $69 million at respective dates) 1,810 1,719
Regulatory assets 230 305
Inventories    
Gas stored underground and fuel oil 68 75
Materials and supplies 763 745
Wildfire Fund asset 295 297
Wildfire self-insurance asset 1,050 1,043
Other 704 644
Total current assets 14,799 15,830
Property, Plant, and Equipment    
Property, Plant, and Equipment 131,319 128,989
Construction work in progress 4,754 4,627
Financing lease ROU asset and other 0 2
Total property, plant, and equipment 136,073 133,618
Accumulated depreciation (37,849) (37,270)
Net property, plant, and equipment 98,224 96,348
Other Noncurrent Assets    
Regulatory assets 15,722 15,981
Customer credit trust 691 804
Nuclear decommissioning trusts 4,185 4,230
Operating lease ROU asset 498 450
Wildfire Fund asset 3,629 3,728
Other (includes noncurrent accounts receivable of $78 million and $67 million related to VIEs, net of noncurrent allowance for doubtful accounts of $19 million and $15 million at respective dates) 4,205 4,240
Total other noncurrent assets 28,930 29,433
TOTAL ASSETS 141,953 141,611
Current Liabilities    
Short-term borrowings 1,675 2,675
Long-term debt, classified as current (includes $222 million and $221 million related to VIEs at respective dates) 622 821
Accounts payable    
Trade creditors 2,836 3,353
Regulatory balancing accounts 1,596 3,119
Other 875 929
Operating lease liabilities 89 90
Interest payable (includes $155 million and $72 million related to VIEs at respective dates) 710 764
Wildfire-related claims 380 524
Other 3,562 4,025
Total current liabilities 12,345 16,300
Noncurrent Liabilities    
Long-term debt (includes $11.6 billion and $11.7 billion related to VIEs at respective dates) 60,146 57,387
Regulatory liabilities 20,265 20,188
Pension and other postretirement benefits 537 549
Asset retirement obligations 5,507 5,439
Deferred income taxes 4,425 4,135
Operating lease liabilities 409 360
Financing lease liabilities 0 2
Other 4,817 4,459
Total noncurrent liabilities 96,106 92,519
Shareholders’ Equity    
Mandatory convertible preferred stock 1,579 1,579
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,202,224,728 and 2,197,942,874 shares outstanding at respective dates 31,605 31,636
Reinvested earnings 97 (650)
Accumulated other comprehensive loss (31) (25)
Total shareholders’ equity 33,250 32,540
Noncontrolling Interest - Preferred Stock of Subsidiary 252 252
Total equity 33,502 32,792
TOTAL LIABILITIES AND EQUITY $ 141,953 $ 141,611
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Mar. 31, 2025
Restricted cash and cash equivalents $ 359 $ 259 $ 383
Allowance for doubtful accounts 407 408  
Accounts receivable, after allowance for credit loss, current 1,928 2,267  
Accrued unbilled revenue 1,436 1,463  
Other (net of allowance for doubtful accounts) 72 69  
Long-term debt, classified as current 622 821  
Interest payable 710 764  
Long-term debt $ 60,146 $ 57,387  
Common stock, shares issued, not disclosed true true  
Common stock, par value (in dollars per share) $ 0 $ 0  
Common stock, shares authorized (in shares) 3,600,000,000 3,600,000,000  
Common stock, shares outstanding (in shares) 2,202,224,728 2,197,942,874  
Variable Interest Entity, Primary Beneficiary      
Restricted cash and cash equivalents $ 325 $ 225  
Allowance for doubtful accounts 407 408  
Accounts receivable, after allowance for credit loss, current 1,600 1,900  
Accrued unbilled revenue 1,300 1,300  
Noncurrent accounts receivable 78 67  
Allowance for doubtful accounts, noncurrent 19 15  
Long-term debt, classified as current 222 221  
Interest payable 155 72  
Long-term debt $ 11,600 $ 11,700  
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Cash Flows from Operating Activities    
Net Income $ 885 $ 634
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation, amortization, and decommissioning 1,166 1,097
Bad debt expense 89 100
Allowance for equity funds used during construction (55) (48)
Deferred income taxes and tax credits, net 294 162
Wildfire Fund expense 102 76
Other (60) (38)
Effect of changes in operating assets and liabilities:    
Accounts receivable 129 37
Wildfire-related insurance receivable 20 (5)
Inventories (11) 31
Accounts payable (4) 91
Wildfire-related claims (144) (166)
Other current assets and liabilities (264) 73
Regulatory assets, liabilities, and balancing accounts, net (74) 922
Other noncurrent assets and liabilities 357 (118)
Net cash provided by operating activities 2,430 2,848
Cash Flows from Investing Activities    
Capital expenditures (3,356) (2,635)
Proceeds from sales and maturities of nuclear decommissioning trust investments 400 278
Purchases of nuclear decommissioning trust investments (434) (317)
Proceeds from sales and maturities of customer credit trust investments 116 99
Purchases of customer credit investments 0 (669)
Proceeds from sales and maturities of self-insurance investments 324 33
Purchases of self-insurance investments (357) (58)
Other 5 5
Net cash used in investing activities (3,302) (3,264)
Cash Flows from Financing Activities    
Borrowings under credit facilities 1,760 0
Repayments under credit facilities (2,760) 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $13 and $15 at respective dates 3,187 1,735
Repayments of long-term debt (600) 0
Mandatory convertible preferred stock dividends paid (24) (23)
Other (38) (24)
Net cash provided by financing activities 1,390 1,609
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents 518 1,193
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 972 1,213
Cash, cash equivalents, restricted cash, and restricted cash equivalents at March 31 1,490 2,406
Less: Restricted cash and restricted cash equivalents (359) (383)
Cash and cash equivalents at March 31 1,131 2,023
Supplemental disclosures of cash flow information    
Interest, net of amounts capitalized (774) (707)
Supplemental disclosures of noncash investing and financing activities    
Capital expenditures financed through accounts payable 1,288 904
Operating lease liabilities arising from obtaining ROU assets 67 3
DWR loan forgiveness and performance-based disbursements 4 74
Common Stock    
Cash Flows from Financing Activities    
Common stock dividends paid (110) (55)
Supplemental disclosures of noncash investing and financing activities    
Dividends declared but not yet paid 111  
Mandatory convertible preferred stock    
Supplemental disclosures of noncash investing and financing activities    
Dividends declared but not yet paid 24 24
AB 1054 Recovery Bonds    
Cash Flows from Financing Activities    
Repayments of recovery bonds $ (25) $ (24)
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Statement of Cash Flows [Abstract]    
Premium, discount, and issuance costs on proceeds from long-term debt $ 13 $ 15
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($)
$ in Millions
Total
Total Shareholders' Equity
Preferred Stock
Common Stock
Reinvested Earnings
Accumulated Other Comprehensive Income (Loss)
Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance at Dec. 31, 2024 $ 30,401 $ 30,149 $ 1,579 $ 31,555 $ (2,966) $ (19) $ 252
Beginning balance (in shares) at Dec. 31, 2024       2,193,573,536      
Increase (Decrease) in Stockholders' Equity [Roll Forward]              
Net Income 634 634     634    
Other comprehensive (loss) income 7 7       7  
Common stock issued, net (in shares)       4,111,477      
Common stock issued, net (1) (1)   $ (1)      
Stock-based compensation amortization (22) (22)   (22)      
Common stock dividends declared (55) (55)     (55)    
Preferred stock dividend requirement of subsidiary (27) (27)     (27)    
Ending balance at Mar. 31, 2025 30,937 30,685 1,579 $ 31,532 (2,414) (12) 252
Ending balance (in shares) at Mar. 31, 2025       2,197,685,013      
Beginning balance at Dec. 31, 2025 $ 32,792 32,540 1,579 $ 31,636 (650) (25) 252
Beginning balance (in shares) at Dec. 31, 2025 2,197,942,874     2,197,942,874      
Increase (Decrease) in Stockholders' Equity [Roll Forward]              
Net Income $ 885 885     885    
Other comprehensive (loss) income (6) (6)       (6)  
Common stock issued, net (in shares)       4,281,854      
Stock-based compensation amortization (31) (31)   $ (31)      
Common stock dividends declared (111) (111)     (111)    
Preferred stock dividend requirement of subsidiary (27) (27)     (27)    
Ending balance at Mar. 31, 2026 $ 33,502 $ 33,250 $ 1,579 $ 31,605 $ 97 $ (31) $ 252
Ending balance (in shares) at Mar. 31, 2026 2,202,224,728     2,202,224,728      
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Operating Revenues    
Total operating revenues $ 6,881 $ 5,983
Operating Expenses    
Operating and maintenance 3,112 2,646
Wildfire-related claims, net of recoveries 0 49
Wildfire Fund expense 102 76
Depreciation, amortization, and decommissioning 1,166 1,097
Total operating expenses 5,411 4,763
Operating Income 1,470 1,220
Interest income 122 117
Interest expense (803) (734)
Other income, net 116 70
Income Before Income Taxes 905 673
Income tax provision 20 39
Net Income 885 634
Preferred stock dividend requirement 27 27
Income Available for Common Shareholders 858 607
Income Available for Common Shareholders 858 607
Utility    
Operating Revenues    
Total operating revenues 6,881 5,983
Operating Expenses    
Operating and maintenance 3,104 2,638
Wildfire-related claims, net of recoveries 0 49
Wildfire Fund expense 102 76
Depreciation, amortization, and decommissioning 1,166 1,097
Total operating expenses 5,403 4,755
Operating Income 1,478 1,228
Interest income 116 114
Interest expense (717) (655)
Other income, net 118 71
Income Before Income Taxes 995 758
Income tax provision 41 63
Net Income 954 695
Preferred stock dividend requirement 3 3
Income Available for Common Shareholders 951 692
Income Available for Common Shareholders 951 692
Electric    
Operating Revenues    
Total operating revenues 4,967 4,135
Operating Expenses    
Cost of electricity and natural gas 561 399
Electric | Utility    
Operating Revenues    
Total operating revenues 4,967 4,135
Operating Expenses    
Cost of electricity and natural gas 561 399
Natural gas    
Operating Revenues    
Total operating revenues 1,914 1,848
Operating Expenses    
Cost of electricity and natural gas 470 496
Natural gas | Utility    
Operating Revenues    
Total operating revenues 1,914 1,848
Operating Expenses    
Cost of electricity and natural gas $ 470 $ 496
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME , UTILITY - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Net Income $ 885 $ 634
Other Comprehensive Income    
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3 and $2 respectively) (6) 7
Total other comprehensive income (loss) (6) 7
Comprehensive Income 879 641
Utility    
Net Income 954 695
Other Comprehensive Income    
Net unrealized gains (losses) on available-for-sale securities (net of taxes of $3 and $2 respectively) (6) 7
Total other comprehensive income (loss) (6) 7
Comprehensive Income $ 948 $ 702
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME , UTILITY (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Net unrealized gain (losses) on available for sale securities, tax $ 3 $ 2
Utility    
Net unrealized gain (losses) on available for sale securities, tax $ 3 $ 2
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Current Assets    
Cash and cash equivalents $ 1,131 $ 713
Restricted cash and restricted cash equivalents (includes $325 million and $225 million related to VIEs at respective dates) 359 259
Accounts receivable    
Customers (net of allowance for doubtful accounts of $407 million and $408 million at respective dates) (includes $1.6 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $407 million and $408 million at respective dates) 1,928 2,267
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,436 1,463
Regulatory balancing accounts 5,025 6,300
Other (net of allowance for doubtful accounts of $72 million and $69 million at respective dates) 1,810 1,719
Regulatory assets 230 305
Inventories    
Gas stored underground and fuel oil 68 75
Materials and supplies 763 745
Wildfire Fund asset 295 297
Wildfire self-insurance asset 1,050 1,043
Other 704 644
Total current assets 14,799 15,830
Property, Plant, and Equipment    
Property, Plant, and Equipment 131,319 128,989
Construction work in progress 4,754 4,627
Financing lease ROU asset and other 0 2
Total property, plant, and equipment 136,073 133,618
Accumulated depreciation (37,849) (37,270)
Net property, plant, and equipment 98,224 96,348
Other Noncurrent Assets    
Regulatory assets 15,722 15,981
Customer credit trust 691 804
Nuclear decommissioning trusts 4,185 4,230
Operating lease ROU asset 498 450
Wildfire Fund asset 3,629 3,728
Other (includes noncurrent accounts receivable of $78 million and $67 million related to VIEs, net of noncurrent allowance for doubtful accounts of $19 million and $15 million at respective dates) 4,205 4,240
Total other noncurrent assets 28,930 29,433
TOTAL ASSETS 141,953 141,611
Current Liabilities    
Short-term borrowings 1,675 2,675
Long-term debt, classified as current (includes $222 million and $221 million related to VIEs at respective dates) 622 821
Accounts payable    
Trade creditors 2,836 3,353
Regulatory balancing accounts 1,596 3,119
Other 875 929
Operating lease liabilities 89 90
Interest payable (includes $155 million and $72 million related to VIEs at respective dates) 710 764
Wildfire-related claims 380 524
Other 3,562 4,025
Total current liabilities 12,345 16,300
Noncurrent Liabilities    
Long-term debt (includes $11.6 billion and $11.7 billion related to VIEs at respective dates) 60,146 57,387
Regulatory liabilities 20,265 20,188
Pension and other postretirement benefits 537 549
Asset retirement obligations 5,507 5,439
Deferred income taxes 4,425 4,135
Operating lease liabilities 409 360
Financing lease liabilities 0 2
Other 4,817 4,459
Total noncurrent liabilities 96,106 92,519
Shareholders’ Equity    
Preferred stock 1,579 1,579
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates 31,605 31,636
Reinvested earnings 97 (650)
Accumulated other comprehensive loss (31) (25)
Total shareholders’ equity 33,250 32,540
TOTAL LIABILITIES AND EQUITY 141,953 141,611
Utility    
Current Assets    
Cash and cash equivalents 441 353
Restricted cash and restricted cash equivalents (includes $325 million and $225 million related to VIEs at respective dates) 358 258
Accounts receivable    
Customers (net of allowance for doubtful accounts of $407 million and $408 million at respective dates) (includes $1.6 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $407 million and $408 million at respective dates) 1,928 2,267
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,436 1,463
Regulatory balancing accounts 5,025 6,300
Other (net of allowance for doubtful accounts of $72 million and $69 million at respective dates) 1,856 1,725
Regulatory assets 230 305
Inventories    
Gas stored underground and fuel oil 68 75
Materials and supplies 763 745
Wildfire Fund asset 295 297
Wildfire self-insurance asset 1,050 1,043
Other 705 643
Total current assets 14,155 15,474
Property, Plant, and Equipment    
Property, Plant, and Equipment 131,319 128,989
Construction work in progress 4,753 4,626
Financing lease ROU asset and other 0 2
Total property, plant, and equipment 136,072 133,617
Accumulated depreciation (37,849) (37,269)
Net property, plant, and equipment 98,223 96,348
Other Noncurrent Assets    
Regulatory assets 15,722 15,981
Customer credit trust 691 804
Nuclear decommissioning trusts 4,185 4,230
Operating lease ROU asset 494 445
Wildfire Fund asset 3,629 3,728
Other (includes noncurrent accounts receivable of $78 million and $67 million related to VIEs, net of noncurrent allowance for doubtful accounts of $19 million and $15 million at respective dates) 4,010 4,073
Total other noncurrent assets 28,731 29,261
TOTAL ASSETS 141,109 141,083
Current Liabilities    
Short-term borrowings 1,675 2,675
Long-term debt, classified as current (includes $222 million and $221 million related to VIEs at respective dates) 622 821
Accounts payable    
Trade creditors 2,833 3,352
Regulatory balancing accounts 1,596 3,119
Other 831 844
Operating lease liabilities 88 90
Interest payable (includes $155 million and $72 million related to VIEs at respective dates) 641 673
Wildfire-related claims 380 524
Other 3,259 3,710
Total current liabilities 11,925 15,808
Noncurrent Liabilities    
Long-term debt (includes $11.6 billion and $11.7 billion related to VIEs at respective dates) 53,535 51,766
Regulatory liabilities 20,265 20,188
Pension and other postretirement benefits 470 482
Asset retirement obligations 5,507 5,439
Deferred income taxes 5,035 4,732
Operating lease liabilities 406 355
Financing lease liabilities 0 2
Other 4,832 4,474
Total noncurrent liabilities 90,050 87,438
Shareholders’ Equity    
Preferred stock 258 258
Common stock, $5 par value, authorized 800,000,000 shares; 800,000,000 shares outstanding at respective dates 1,322 1,322
Additional paid-in capital 38,482 37,505
Reinvested earnings (899) (1,225)
Accumulated other comprehensive loss (29) (23)
Total shareholders’ equity 39,134 37,837
TOTAL LIABILITIES AND EQUITY $ 141,109 $ 141,083
v3.26.1
CONDENSED CONSOLIDATED BALANCE SHEETS, UTILITY (Parenthetical) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Restricted cash and cash equivalents $ 359 $ 259
Allowance for doubtful accounts 407 408
Accounts receivable, after allowance for credit loss, current 1,928 2,267
Accrued unbilled revenue 1,436 1,463
Other (net of allowance for doubtful accounts) 72 69
Long-term debt, classified as current 622 821
Interest payable 710 764
Long-term debt $ 60,146 $ 57,387
Common stock, shares issued, not disclosed true true
Common stock, par value (in dollars per share) $ 0 $ 0
Common stock, shares authorized (in shares) 3,600,000,000 3,600,000,000
Common stock, shares outstanding (in shares) 2,202,224,728 2,197,942,874
Utility    
Restricted cash and cash equivalents $ 358 $ 258
Allowance for doubtful accounts 407 408
Accounts receivable, after allowance for credit loss, current 1,928 2,267
Accrued unbilled revenue 1,436 1,463
Other (net of allowance for doubtful accounts) 72 69
Long-term debt, classified as current 622 821
Interest payable 641 673
Long-term debt $ 53,535 $ 51,766
Common stock, shares issued, not disclosed true true
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) 800,000,000 800,000,000
Variable Interest Entity, Primary Beneficiary    
Restricted cash and cash equivalents $ 325 $ 225
Allowance for doubtful accounts 407 408
Accounts receivable, after allowance for credit loss, current 1,600 1,900
Accrued unbilled revenue 1,300 1,300
Allowance for doubtful accounts, noncurrent 19 15
Noncurrent accounts receivable 78 67
Long-term debt, classified as current 222 221
Interest payable 155 72
Long-term debt 11,600 11,700
Variable Interest Entity, Primary Beneficiary | Utility    
Restricted cash and cash equivalents 325 225
Allowance for doubtful accounts 407 408
Accounts receivable, after allowance for credit loss, current 1,600 1,900
Accrued unbilled revenue 1,300 1,300
Allowance for doubtful accounts, noncurrent 78 67
Noncurrent accounts receivable 19 15
Long-term debt, classified as current 222 221
Interest payable 155 72
Long-term debt $ 11,600 $ 11,700
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Cash Flows from Operating Activities    
Net income $ 885 $ 634
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation, amortization, and decommissioning 1,166 1,097
Bad debt expense 89 100
Allowance for equity funds used during construction (55) (48)
Deferred income taxes and tax credits, net 294 162
Wildfire Fund expense 102 76
Other (60) (38)
Effect of changes in operating assets and liabilities:    
Accounts receivable 129 37
Wildfire-related insurance receivable 20 (5)
Inventories (11) 31
Accounts payable (4) 91
Wildfire-related claims (144) (166)
Other current assets and liabilities (264) 73
Regulatory assets, liabilities, and balancing accounts, net (74) 922
Other noncurrent assets and liabilities 357 (118)
Net cash provided by operating activities 2,430 2,848
Cash Flows from Investing Activities    
Capital expenditures (3,356) (2,635)
Proceeds from sales and maturities of nuclear decommissioning trust investments 400 278
Purchases of nuclear decommissioning trust investments (434) (317)
Proceeds from sales and maturities of customer credit trust investments 116 99
Purchases of customer credit investments 0 (669)
Proceeds from sales and maturities of self-insurance investments 324 33
Purchases of self-insurance investments (357) (58)
Other 5 5
Net cash used in investing activities (3,302) (3,264)
Cash Flows from Financing Activities    
Borrowings under credit facilities 1,760 0
Repayments under credit facilities (2,760) 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $3 and $15 at respective dates 3,187 1,735
Repayments of long-term debt (600) 0
Preferred stock dividends paid (24) (23)
Other (38) (24)
Net cash provided by financing activities 1,390 1,609
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents 518 1,193
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 972 1,213
Cash, cash equivalents, restricted cash, and restricted cash equivalents at March 31 1,490 2,406
Less: Restricted cash and restricted cash equivalents (359) (383)
Cash and cash equivalents at March 31 1,131 2,023
Supplemental disclosures of cash flow information    
Interest, net of amounts capitalized (774) (707)
Supplemental disclosures of noncash investing and financing activities    
Capital expenditures financed through accounts payable 1,288 904
Operating lease liabilities arising from obtaining ROU assets 67 3
DWR loan forgiveness and performance-based disbursements 4 74
AB 1054 Recovery Bonds    
Cash Flows from Financing Activities    
Repayments of recovery bonds (25) (24)
Utility    
Cash Flows from Operating Activities    
Net income 954 695
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation, amortization, and decommissioning 1,166 1,097
Bad debt expense 89 100
Allowance for equity funds used during construction (55) (48)
Deferred income taxes and tax credits, net 306 180
Wildfire Fund expense 102 76
Other (30) (22)
Effect of changes in operating assets and liabilities:    
Accounts receivable 89 (2)
Wildfire-related insurance receivable 20 (5)
Inventories (11) 31
Accounts payable 38 92
Wildfire-related claims (144) (166)
Other current assets and liabilities (248) 122
Regulatory assets, liabilities, and balancing accounts, net (74) 922
Other noncurrent assets and liabilities 386 (117)
Net cash provided by operating activities 2,588 2,955
Cash Flows from Investing Activities    
Capital expenditures (3,356) (2,635)
Proceeds from sales and maturities of nuclear decommissioning trust investments 400 278
Purchases of nuclear decommissioning trust investments (434) (317)
Proceeds from sales and maturities of customer credit trust investments 116 99
Purchases of customer credit investments 0 (669)
Proceeds from sales and maturities of self-insurance investments 324 33
Purchases of self-insurance investments (357) (58)
Other 5 5
Net cash used in investing activities (3,302) (3,264)
Cash Flows from Financing Activities    
Borrowings under credit facilities 1,760 0
Repayments under credit facilities (2,760) 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $3 and $15 at respective dates 2,197 1,735
Repayments of long-term debt (600) 0
Preferred stock dividends paid (3) (3)
Common stock dividends paid (625) (575)
Equity contribution from PG&E Corporation 977 450
Other (19) (8)
Net cash provided by financing activities 902 1,575
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents 188 1,266
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 611 977
Cash, cash equivalents, restricted cash, and restricted cash equivalents at March 31 799 2,243
Less: Restricted cash and restricted cash equivalents (358) (383)
Cash and cash equivalents at March 31 441 1,860
Supplemental disclosures of cash flow information    
Interest, net of amounts capitalized (668) (599)
Supplemental disclosures of noncash investing and financing activities    
Capital expenditures financed through accounts payable 1,288 904
Operating lease liabilities arising from obtaining ROU assets 67 3
DWR loan forgiveness and performance-based disbursements 4 74
Utility | AB 1054 Recovery Bonds    
Cash Flows from Financing Activities    
Repayments of recovery bonds $ (25) $ (24)
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY (Parenthetical) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Premium, discount, and issuance costs on proceeds from long-term debt $ 13 $ 15
Utility    
Premium, discount, and issuance costs on proceeds from long-term debt $ 3 $ 15
v3.26.1
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY, UTILITY - USD ($)
$ in Millions
Total
Utility
Total Shareholders' Equity
Total Shareholders' Equity
Utility
Preferred Stock
Preferred Stock
Utility
Common Stock
Common Stock
Utility
Additional Paid-in Capital
Utility
Reinvested Earnings
Reinvested Earnings
Utility
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss)
Utility
Beginning balance at Dec. 31, 2024 $ 30,401   $ 30,149 $ 35,550 $ 1,579 $ 258 $ 31,555 $ 1,322 $ 35,930 $ (2,966) $ (1,940) $ (19) $ (20)
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net Income 634 $ 695 634 695           634 695    
Other comprehensive (loss) income 7 7 7 7               7 7
Equity contribution       450         450        
Common stock dividend (55)   (55) (575)           (55) (575)    
Preferred stock dividend requirement       (3)             (3)    
Ending balance at Mar. 31, 2025 30,937   30,685 36,124 1,579 258 31,532 1,322 36,380 (2,414) (1,823) (12) (13)
Beginning balance at Dec. 31, 2025 32,792   32,540 37,837 1,579 258 31,636 1,322 37,505 (650) (1,225) (25) (23)
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net Income 885 954 885 954           885 954    
Other comprehensive (loss) income (6) $ (6) (6) (6)               (6) (6)
Equity contribution       977         977        
Common stock dividend (111)   (111) (625)           (111) (625)    
Preferred stock dividend requirement       (3)             (3)    
Ending balance at Mar. 31, 2026 $ 33,502   $ 33,250 $ 39,134 $ 1,579 $ 258 $ 31,605 $ 1,322 $ 38,482 $ 97 $ (899) $ (31) $ (29)
v3.26.1
ORGANIZATION AND BASIS OF PRESENTATION
 3 Months Ended
Mar. 31, 2026
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 Form 10-Q is a combined report of PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed 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 Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments which are, in the opinion of the management, of a normal recurring nature and necessary to a fair statement of the results for the interim periods presented. The information as of December 31, 2025 in the Condensed Consolidated Balance Sheets included in this Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2025 Form 10-K. This Form 10-Q should be read in conjunction with the 2025 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, asset retirement obligations, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed 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.
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 3 Months Ended
Mar. 31, 2026
Accounting Policies [Abstract]  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker (“CODM”) is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the CODM uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Condensed Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the CODM is not regularly provided with information that is considered to be significant under Accounting Standards Codification (“ASC”) 280, Segment Reporting. Except for publicly available information, the information regularly provided to the CODM consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.
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 Condensed Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass through 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:
Three Months Ended March 31,
(in millions)20262025
Electric
Revenue from contracts with customers
   Residential$1,807 $1,834 
   Commercial1,592 1,506 
   Industrial438 414 
   Agricultural205 199 
   Public street and highway lighting26 27 
   Other, net (1)
293 89 
Total revenue from contracts with customers - electric4,361 4,069 
Regulatory balancing accounts (2)
606 66 
Total electric operating revenue$4,967 $4,135 
Natural gas
Revenue from contracts with customers
   Residential$1,480 $1,709 
   Commercial368 399 
   Transportation service only490 546 
   Other, net (1)
(322)(120)
Total revenue from contracts with customers - gas2,016 2,534 
Regulatory balancing accounts (2)
(102)(686)
Total natural gas operating revenue1,914 1,848 
Total operating revenues$6,881 $5,983 
(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 alternative revenues authorized to be billed or refunded to customers.
Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of March 31, 2026, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.

Expected credit losses of $89 million and $100 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables during the three months ended March 31, 2026 and 2025, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of March 31, 2026, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $60 million and $88 million, respectively. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. The RUBA current balancing account balance decreased from December 31, 2025 to March 31, 2026 primarily due to the annual electric and gas rate true-up, which allows the Utility to recover approximately $278 million in undercollections from residential customers in 2026.
Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of March 31, 2026, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Government Assistance

The Utility participated in various government assistance programs during the three months ended March 31, 2026 and 2025. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).
DWR Loan Agreement

On October 18, 2022, the DWR and the Utility entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final proceeds were received in 2024, and no further disbursements will be made.

The Utility initially accounted for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:
Three Months Ended March 31,
(in millions)
20262025
Long-term debt:
Beginning Balance - DWR loan outstanding
$738 $886 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
— (8)
Operating and maintenance expense - Loan forgiveness and other adjustments
(4)(57)
Other current liabilities:
Change in performance-based disbursements deferred
— (9)
Long-term debt:
Ending Balance - DWR loan outstanding$734 $812 
U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and the DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the three months ended March 31, 2026 and 2025, the Condensed Consolidated Statements of Income reflected $10 million and $40 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three months ended March 31, 2026, the amount recorded as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP was immaterial to the Condensed Consolidated Statements of Income. During the three months ended March 31, 2025, the Condensed Consolidated Statements of Income reflected $41 million as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP.
Variable Interest Entities

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

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Condensed Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. As of March 31, 2026 and December 31, 2025, the SPV had net accounts receivable of $2.9 billion and $3.2 billion, respectively, and outstanding borrowings of $1.8 billion, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate Recovery Property.
PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of March 31, 2026 and December 31, 2025, PG&E Recovery Funding LLC had outstanding borrowings of $3.0 billion and $3.1 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate of $7.5 billion of senior secured recovery bonds. As of March 31, 2026 and December 31, 2025, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs as of March 31, 2026, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of March 31, 2026, it did not consolidate any of them.
Contributions to the Wildfire Fund and the Continuation Account

AB 1054 did not specify a period of coverage for the Wildfire Fund, and so the accounting treatment is subject to significant judgments and estimates. PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below.

In estimating the life of the fund, PG&E Corporation and the Utility use a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. PG&E Corporation’s and the Utility’s initial estimated life of the fund was 15 years. In 2024, a re-evaluation resulted in the estimated life increasing from 15 to 20 years.
The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

PG&E Corporation and the Utility have an established process to re-evaluate the estimated life of the fund whenever they obtain new significant fire-loss data. PG&E Corporation and the Utility consider significant fire-loss data to include Cal Fire’s annual release of the prior year’s fire-loss data, internally developed data about wildfires and wildfire conditions in their own service area, and other participating electric utilities’ public disclosures of probable and estimable wildfire-related losses in their service area. PG&E Corporation and the Utility are not able to independently verify other utilities’ estimates. During each re-evaluation, PG&E Corporation and the Utility update their assumptions and the dataset of historical fire-losses for wildfires caused by electrical equipment, as applicable. Based upon the outcome of the newly run Monte Carlo simulations, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. PG&E Corporation and the Utility apply adjustments to the estimated life of the fund on a prospective basis.

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable. On February 18, 2026, SCE disclosed in its Annual Report on Form 10-K for the year ended December 31, 2025 that it has entered into settlements with insurance claimants and claimants under its Wildfire Recovery Compensation Program related to the Eaton fire. As of December 31, 2025, SCE had recorded $1.1 billion in losses related to these settlements. SCE also recorded expected recoveries from the Wildfire Fund of $134 million. As a result, PG&E Corporation and the Utility accelerated the amortization of the Wildfire Fund asset during the three months ended March 31, 2026 as described below.

As of March 31, 2026, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $378 million in Other noncurrent liabilities, $295 million in Current assets - Wildfire Fund asset, and $3.6 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended March 31, 2026 and 2025, the Utility recorded amortization and accretion expense of $102 million and $76 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income.

PG&E Corporation and the Utility expect to begin accounting for the Continuation Account if the Wildfire Fund administrator determines that the Continuation Account is necessary and the CPUC approves the extension of non-bypassable charges to customers.

For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 below.
Pension and Other Post-Retirement Benefits

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.
The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2026 and 2025 were as follows:
Pension BenefitsOther Benefits
Three Months Ended March 31,
(in millions)2026202520262025
Service cost for benefits earned (1)
$115 $106 $11 $9 
Interest cost256 252 20 18 
Expected return on plan assets(307)(263)(39)(37)
Amortization of prior service cost (credit)(1)(1)1 1 
Amortization of net actuarial loss (gain)1 — (4)(6)
Net periodic benefit cost64 94 (11)(15)
Regulatory account transfer (2)
20 (10)— — 
Total$84 $84 $(11)$(15)
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery or refund through rates in future periods.

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

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) consisted of the following:
Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
(in millions, net of income tax)Three Months Ended March 31, 2026
Beginning balance$(47)$19 $8 $(20)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $3, respectively)
— — (6)(6)
Amounts reclassified from other comprehensive income: (1)
Amortization of net actuarial gain (net of taxes of $0, $1, and $0, respectively)
— (2)— (2)
Regulatory account transfer (net of taxes of $0, $1, and $0, respectively)
— 2 — 2 
Net current period other comprehensive (loss)— — (6)(6)
Ending balance$(47)$19 $2 $(26)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and self-insurance.
Pension BenefitsOther
Benefits
Available-for-Sale Securities(2)
Total
(in millions, net of income tax)Three Months Ended March 31, 2025
Beginning balance$(35)$18 $3 $(14)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0, and $2 respectively)
— — 7 7 
Amounts reclassified from other comprehensive income: (1)
Amortization of net actuarial gain (net of taxes of $0, $1, and $0, respectively)
— (4)— (4)
Regulatory account transfer (net of taxes of $0, $1, and $0, respectively)
— 4 — 4 
Net current period other comprehensive gain— — 7 7 
Ending balance$(35)$18 $10 $(7)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.

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

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU became effective for PG&E Corporation and the Utility on January 1, 2026. The adoption of this ASU did not have an immediate impact and is not expected to have a significant impact in future periods on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures.
Accounting Standards Issued But Not Yet Adopted

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amended the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
Intangibles – Goodwill and Other – Internal Use Software
In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40), which amended the existing guidance to modernize the accounting for software costs that are accounted for under Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this ASU remove all references to prescriptive and sequential software development stages throughout Subtopic 350-40. Therefore, an entity is required to start capitalizing software costs when both of the following occur: (1) management has authorized and committed to funding the software project, and (2) it is probable that the project will be completed, and the software will be used to perform the function. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
v3.26.1
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
 3 Months Ended
Mar. 31, 2026
Regulated Operations [Abstract]  
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets

Noncurrent regulatory assets are comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Pension benefits
$381 $400 
Environmental compliance costs1,140 1,158 
Price risk management97 100 
Catastrophic event memorandum account
466 666 
Wildfire-related accounts
1,360 1,626 
Deferred income taxes6,460 6,157 
Financing costs199 202 
SB 901 securitization
5,058 5,089 
Other561 583 
Total noncurrent regulatory assets$15,722 $15,981 
Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Cost of removal obligations
$9,680 $9,488 
Public purpose programs
1,203 1,169 
Employee benefit plans
1,049 1,043 
Transmission tower wireless licenses
254 257 
SB 901 securitization
5,898 6,010 
Wildfire self-insurance
1,041 1,035 
Other1,140 1,186 
Total noncurrent regulatory liabilities
$20,265 $20,188 
Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:
Balance at
(in millions)March 31, 2026December 31, 2025
Electric distribution
$2,796 $1,465 
Electric transmission
133 122 
Gas distribution and transmission
89 142 
Energy procurement
1,184 2,711 
Public purpose programs
258 151 
Wildfire-related accounts
71 84 
Residential uncollectibles balancing accounts
60 278 
Catastrophic event memorandum account
27 181 
Other407 1,166 
Total regulatory balancing accounts receivable$5,025 $6,300 

Balance at
(in millions)March 31, 2026December 31, 2025
Electric transmission
$9 $37 
Gas distribution and transmission
92 78 
Energy procurement
75 1,502 
Public purpose programs
492 472 
SFGO sale20 83 
Wildfire-related accounts
420 338 
Nuclear decommissioning adjustment mechanism
1 1 
Other487 608 
Total regulatory balancing accounts payable$1,596 $3,119 

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.
v3.26.1
DEBT
 3 Months Ended
Mar. 31, 2026
Debt Disclosure [Abstract]  
DEBT DEBT
Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of March 31, 2026:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facility June 2030$5,400 
(1)
$(575)$(291)$4,534 
Utility Receivables Securitization Program (2)
June 20271,750 
(3)
(1,750)— — 
(3)
PG&E Corporation revolving credit facilityJune 2028650 — — 650 
Total credit facilities$7,800 $(2,325)$(291)$5,184 
(1) Includes a $2.0 billion letter of credit sublimit.
(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.
(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
Long-Term Debt Issuances and Redemptions

Utility

On February 20, 2026, the Utility completed the sale of (i) $400 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.0 billion aggregate principal amount of 5.200% First Mortgage Bonds due 2036 and (iii) $800 million aggregate principal amount of 6.000% First Mortgage Bonds due 2056. The Utility used the net proceeds of such issuances for repayment of $600 million aggregate principal amount of 2.95% First Mortgage Bonds due March 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

PG&E Corporation

On February 19, 2026, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056. These notes initially bear interest at the rate of 6.850% per annum, and beginning September 15, 2031 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.225% (but not below 6.850%). PG&E Corporation used the net proceeds for general corporate purposes, including repayment of indebtedness.
Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”).

As of both March 31, 2026 and December 31, 2025, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion, with unamortized debt issuance costs of $11 million and $13 million, respectively, included in Long-term debt. For both the three months ended March 31, 2026 and 2025, the Condensed Consolidated Statements of Income reflected the total interest expense of approximately $23 million.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. As of March 31, 2026, none of the conditions allowing holders of the Convertible Notes to convert had been met.
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 9 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the three months ended March 31, 2026 and 2025.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. As of March 31, 2026, the Utility had made all required upfront contributions. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three months ended March 31, 2026, the Utility recorded $82 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the three months ended March 31, 2025, the Utility recorded $74 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income.
The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:
SB 901 securitization regulatory asset
(in millions)
20262025
Balance at January 1
$5,089 $5,194 
Amortization
(31)(19)
Balance at March 31
$5,058 $5,175 

SB 901 securitization regulatory liability
(in millions)
20262025
Balance at January 1$(6,010)$(6,295)
Amortization
11393
Additions(1)
(1)(1)
Balance at March 31
$(5,898)$(6,203)
(1) Includes $1 million of returns on investments in the customer credit trust expected to be credited to customers for each of the three months ended March 31, 2026 and 2025.
v3.26.1
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
 3 Months Ended
Mar. 31, 2026
Debt Disclosure [Abstract]  
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST DEBT
Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of March 31, 2026:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facility June 2030$5,400 
(1)
$(575)$(291)$4,534 
Utility Receivables Securitization Program (2)
June 20271,750 
(3)
(1,750)— — 
(3)
PG&E Corporation revolving credit facilityJune 2028650 — — 650 
Total credit facilities$7,800 $(2,325)$(291)$5,184 
(1) Includes a $2.0 billion letter of credit sublimit.
(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.
(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
Long-Term Debt Issuances and Redemptions

Utility

On February 20, 2026, the Utility completed the sale of (i) $400 million aggregate principal amount of 6.100% First Mortgage Bonds due 2029, (ii) $1.0 billion aggregate principal amount of 5.200% First Mortgage Bonds due 2036 and (iii) $800 million aggregate principal amount of 6.000% First Mortgage Bonds due 2056. The Utility used the net proceeds of such issuances for repayment of $600 million aggregate principal amount of 2.95% First Mortgage Bonds due March 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

PG&E Corporation

On February 19, 2026, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056. These notes initially bear interest at the rate of 6.850% per annum, and beginning September 15, 2031 and every five year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.225% (but not below 6.850%). PG&E Corporation used the net proceeds for general corporate purposes, including repayment of indebtedness.
Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”).

As of both March 31, 2026 and December 31, 2025, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion, with unamortized debt issuance costs of $11 million and $13 million, respectively, included in Long-term debt. For both the three months ended March 31, 2026 and 2025, the Condensed Consolidated Statements of Income reflected the total interest expense of approximately $23 million.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. As of March 31, 2026, none of the conditions allowing holders of the Convertible Notes to convert had been met.
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 9 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the three months ended March 31, 2026 and 2025.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. As of March 31, 2026, the Utility had made all required upfront contributions. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three months ended March 31, 2026, the Utility recorded $82 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income. During the three months ended March 31, 2025, the Utility recorded $74 million for amortization of the regulatory asset and liability in the Condensed Consolidated Statements of Income.
The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:
SB 901 securitization regulatory asset
(in millions)
20262025
Balance at January 1
$5,089 $5,194 
Amortization
(31)(19)
Balance at March 31
$5,058 $5,175 

SB 901 securitization regulatory liability
(in millions)
20262025
Balance at January 1$(6,010)$(6,295)
Amortization
11393
Additions(1)
(1)(1)
Balance at March 31
$(5,898)$(6,203)
(1) Includes $1 million of returns on investments in the customer credit trust expected to be credited to customers for each of the three months ended March 31, 2026 and 2025.
v3.26.1
EQUITY
 3 Months Ended
Mar. 31, 2026
Equity [Abstract]  
EQUITY EQUITY
Dividends

Subject to the dividend restrictions as described in Notes 6 and 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s and the Utility’s 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.

The following table summarizes the dividends paid or declared by PG&E Corporation and the Utility in 2026:

SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation common stock$0.05 $110 December 11, 2025December 31, 2025January 15, 2026
0.05111 February 19, 2026March 31, 2026April 15, 2026
Utility common stock
(1)
625 February 19, 2026
(1)
March 30, 2026
PG&E Corporation mandatory convertible preferred stock0.7524 December 11, 2025February 13, 2026March 1, 2026
0.75 24 February 19, 2026May 15, 2026June 1, 2026
Utility preferred stockvaries by series3.5 December 11, 2025January 30, 2026February 15, 2026
varies by series3.5 February 19, 2026April 30, 2026May 15, 2026
(1) PG&E Corporation owns all of the outstanding shares of the Utility’s common stock.
v3.26.1
EARNINGS PER SHARE
 3 Months Ended
Mar. 31, 2026
Earnings Per Share [Abstract]  
EARNINGS PER SHARE EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the Income available for common shareholders, basic, by the weighted average number of common shares outstanding, basic. PG&E Corporation’s diluted EPS is calculated by dividing the income available for common shareholders, diluted, by the weighted average number of common shares outstanding, diluted.  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 available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
Three Months Ended March 31,
(in millions, except per share amounts)20262025
Numerator:
Income available for common shareholders, basic$858 $607 
Mandatory Convertible Preferred Stock dividends24 — 
Income available for common shareholders, diluted$882 $607 
Denominator:
Weighted average common shares outstanding, basic(1)
2,199 2,195 
Dilutive effect of Employee stock-based compensation4 5 
Dilutive effect of Mandatory Convertible Preferred Stock78 — 
Weighted average common shares outstanding, diluted2,281 2,200 
Total income per common share:
Basic$0.39 $0.28 
Diluted$0.39 $0.28 
(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

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.
v3.26.1
DERIVATIVES
 3 Months Ended
Mar. 31, 2026
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVES DERIVATIVES
Use of Derivative Instruments

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

Derivatives are presented in the Utility’s Condensed 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 Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed 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 Condensed Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume at
Underlying ProductInstrumentsMarch 31, 2026December 31, 2025
Natural Gas (1) (MMBtus (2))
Forwards, futures, and swaps204,557,995 232,825,834 
 Options34,175,000 48,215,000 
Electricity (MWh)Forwards, futures, and swaps6,903,828 7,196,942 
Options2,678,000 1,650,800 
 
Congestion Revenue Rights (3)
83,584,734 93,712,644 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of March 31, 2026, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$152 $(28)$19 $143 
Noncurrent assets – other156 (2)— 154 
Current liabilities – other(103)28 11 (64)
Noncurrent liabilities – other(99)2 — (97)
Total commodity risk$106 $— $30 $136 

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$165 $(46)$— $119 
Noncurrent assets – other170 (6)— 164 
Current liabilities – other(169)46 — (123)
Noncurrent liabilities – other(106)6 — (100)
Total commodity risk$60 $— $— $60 

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

Some of the Utility’s derivative 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. One major credit agency continues to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of March 31, 2026, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
v3.26.1
FAIR VALUE MEASUREMENTS
 3 Months Ended
Mar. 31, 2026
Fair Value Disclosures [Abstract]  
FAIR VALUE MEASUREMENTS FAIR VALUE MEASUREMENTS
PG&E Corporation and the Utility measure their cash equivalents, self-insurance assets, 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 March 31, 2026
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments
$1,016 $— $— $— $1,016 
Self-insurance investments
   Short-term investments1,178 — — — 1,178 
Total Self-insurance investments (2)
1,178 — — — 1,178 
Nuclear decommissioning trusts
Short-term investments53 — — — 53 
Global equity securities2,336 — — — 2,336 
Fixed-income securities1,518 1,107 — — 2,625 
Assets measured at NAV— — — — 25 
Total nuclear decommissioning trusts (3)
3,907 1,107 — — 5,039 
Customer credit trust
Short-term investments127 — — — 127 
Global equity securities— — — — — 
Fixed-income securities178 386 — — 564 
Total customer credit trust
305 386 — — 691 
Price risk management instruments (Note 8)
     
Electricity— 31 260 (9)282 
Gas— 17 — (2)15 
Total price risk management instruments— 48 260 (11)297 
Rabbi trusts     
Short-term investments117 — — — 117 
Global equity securities5 — — — 5 
Life insurance contracts— 65 — — 65 
Total rabbi trusts122 65 — — 187 
Long-term disability trust     
Short-term investments1 — — — 1 
Assets measured at NAV— — — — 127 
Total long-term disability trust1 — — — 128 
TOTAL ASSETS$6,529 $1,606 $260 $(11)$8,536 
Liabilities:     
Price risk management instruments (Note 8)
     
Electricity$— $31 $168 $(39)$160 
Gas— 3 — (2)1 
TOTAL LIABILITIES$— $34 $168 $(41)$161 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Includes approximately $1 billion and $119 million held in the entities for wildfire and non-wildfire self-insurance, respectively.
(3) Represents amount before deducting $854 million primarily related to deferred taxes on appreciation of investment value.
 Fair Value Measurements
 
At December 31, 2025
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$634 $— $— $— $634 
Self-insurance investments
    Short-term investments1,120 — — — 1,120 
Total Self-insurance investments(2)
1,120 — — — 1,120 
Nuclear decommissioning trusts
Short-term investments94 — — — 94 
Global equity securities2,433 — — — 2,433 
Fixed-income securities1,445 1,113 — — 2,558 
Assets measured at NAV— — — — 26 
Total nuclear decommissioning trusts (3)
3,972 1,113 — — 5,111 
Customer credit trust
Short-term investments111 — — — 111 
Global equity securities— — — — 
Fixed-income securities367 326 — — 693 
Total customer credit trust
478 326 — — 804 
Price risk management instruments (Note 8)
    
Electricity— 19 283 (6)296 
Gas— 33 — (46)(13)
Total price risk management instruments— 52 283 (52)283 
Rabbi trusts    
Short-term investments115 — — — 115 
Global equity securities5 — — — 5 
Life insurance contracts— 65 — — 65 
Total rabbi trusts120 65 — — 185 
Long-term disability trust    
Short-term investments10 — — — 10 
Assets measured at NAV— — — — 127 
Total long-term disability trust10 — — — 137 
TOTAL ASSETS$6,334 $1,556 $283 $(52)$8,274 
Liabilities:    
Price risk management instruments (Note 8)
    
Electricity$— $80 $130 $(6)$204 
Gas— 65 — (46)19 
TOTAL LIABILITIES$— $145 $130 $(52)$223 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Includes $1 billion and $77 million held in the entities for wildfire and non-wildfire self-insurance, respectively.
(3) Represents amount before deducting $881 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 three months ended March 31, 2026 or 2025.
Trust Assets

Assets Measured at Fair Value

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

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

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

Assets Measured at NAV Using Practical Expedient

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

Self-insurance investments

Investments held in Pacific Energy Risk Solutions, LLC and Pacific Casualty Insurance Company, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.
Price Risk Management Instruments

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

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

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

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

Level 3 Measurements and Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments.  See Note 8 above.
 Fair Value
(in millions)		   
At March 31, 2026Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$229 $75 Market approachCRR auction prices
$ (79) - 74 / 2
Power purchase agreements$31 $93 Discounted cash flowForward prices
$ 10 - 102 / 51
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

 Fair Value
(in millions)		   
At December 31, 2025Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$252 $83 Market approachCRR auction prices
$ (74) - 74 / 2
Power purchase agreements$31 $47 Discounted cash flowForward prices
$ 11 - 106 / 53
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2026 and 2025:
 Price Risk Management Instruments
(in millions)20262025
Asset balance as of January 1$153 $127 
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)
(61)(1)
Asset balance as of March 31$92 $126 
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets, and net income is not impacted.
Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, and customer deposits approximate their carrying values as of March 31, 2026 and December 31, 2025, 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 March 31, 2026
At December 31, 2025
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount
Level 2 Fair Value
Debt (Note 4)    
PG&E Corporation (1)
$6,326 $6,715 $5,360 $5,697 
Utility41,887 38,779 38,145 35,565 
(1) As of March 31, 2026, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.
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 March 31, 2026
    
Nuclear decommissioning trusts    
Short-term investments$53 $— $— $53 
Global equity securities323 2,045 (7)2,361 
Fixed-income securities2,647 30 (52)2,625 
Total (1)
$3,023 $2,075 $(59)$5,039 
As of December 31, 2025    
Nuclear decommissioning trusts    
Short-term investments$94 $— $— $94 
Global equity securities324 2,140 (5)2,459 
Fixed-income securities2,557 48 (47)2,558 
Total (1)
$2,975 $2,188 $(52)$5,111 
(1) Represents amounts before deducting $854 million and $881 million as of March 31, 2026 and December 31, 2025, 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)March 31, 2026
Less than 1 year$58 
1–5 years904 
5–10 years592 
More than 10 years1,071 
Total maturities of fixed-income securities$2,625 
The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended March 31,
(in millions)20262025
Proceeds from sales and maturities of nuclear decommissioning trust investments$400 $278 
Gross realized gains on securities21 2 
Gross realized losses on securities(8)(6)
Customer Credit Trust

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 March 31, 2026
Customer credit trust
Short-term investments$127 $— $— $127 
Global equity securities— — — — 
Fixed-income securities566 1 (3)564 
Total
$693 $1 $(3)$691 
As of December 31, 2025    
Customer credit trust    
Short-term investments$111 $— $— $111 
Global equity securities— — — — 
Fixed-income securities689 5 (1)693 
Total
$800 $5 $(1)$804 
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)March 31, 2026
Less than 1 year$22 
1–5 years354 
5–10 years51 
More than 10 years137 
Total maturities of fixed-income securities$564 
The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended
March 31,
(in millions)20262025
Proceeds from sales and maturities of customer credit trust investments$116 $99 
Gross realized gains on securities5 3 
Gross realized losses on securities
(3)(3)
v3.26.1
WILDFIRE-RELATED CONTINGENCIES
 3 Months Ended
Mar. 31, 2026
Commitments and Contingencies Disclosure [Abstract]  
WILDFIRE-RELATED CONTINGENCIES WILDFIRE-RELATED CONTINGENCIES
Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that 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 record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.
Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, 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.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages, and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.
The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. Claims related to the 2019 Kincade fire are subject to the 40% limitation on the allowed amount of 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 the possession of Cal Fire, USFS, or the relevant district attorney’s office, 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.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through March 31, 2026.
Payments (in millions)
2019 Kincade Fire
$1,318 
2021 Dixie Fire2,009 
2022 Mosquito Fire169 
Total at March 31, 2026
$3,496 
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

As of April 15, 2026, PG&E Corporation and the Utility have settled or reached settlements in principle with substantially all known individual plaintiffs.

In October 2022, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.325 billion as of December 31, 2025 (before available insurance). The aggregate liability remained unchanged as of March 31, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include any claims related to Cal OES.

The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$38 
Accrued Losses— 
Payments(31)
Balance at March 31, 2026
$7 

The Utility has fully collected its liability insurance coverage for third-party liability attributable to the 2019 Kincade fire, which was for an aggregate amount of $430 million.

As of March 31, 2026, the Utility had received $115 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below.
2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, through its ongoing investigation, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in the Utility’s proceeding for review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire under AB 1054 or a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of April 15, 2026, PG&E Corporation and the Utility are aware of approximately 190 complaints on behalf of at least 9,062 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A trial with respect to one plaintiff has been scheduled for December 2, 2026. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025. No bellwether trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On April 30, 2025, in response to the Court of Appeal’s request, Cal Fire filed an opposition to the Utility’s writ. The Utility filed a reply to the opposition on May 9, 2025. On February 13, 2026, the Court of Appeal denied the writ without opinion. The Utility filed a petition for review with the California Supreme Court, and on April 22, 2026, the California Supreme Court granted the petition for review and transferred the matter back to the Court of Appeal, with directions to vacate its order denying mandate and to issue an order to show cause why the relief sought in the petition should not be granted.

In February 2023, the Utility entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, and the hearing date on the motion is scheduled for July 8, 2026.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $2.15 billion as of December 31, 2025 (before available recoveries). The aggregate liability remained unchanged as of March 31, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.15 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses— 
Payments(101)
Balance at March 31, 2026
$142 

As of March 31, 2026, the Utility recorded an insurance receivable of $521 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $1.15 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $892 million as of March 31, 2026. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of March 31, 2026, the Utility also recorded a $97 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $539 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA.
2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. 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 2022 Mosquito fire. This investigation is ongoing.

As of April 15, 2026, PG&E Corporation and the Utility are aware of approximately 30 complaints on behalf of at least 2,931 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and the Regents of the University of California have each filed a complaint. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into a settlement agreement with five public entities, and their complaint was dismissed on February 4, 2026. In April 2026, PG&E Corporation and the Utility entered into a settlement agreement with PCWA and Middle Fork Project Finance Authority. The court vacated the previously scheduled individual claimant bellwether trial date for April 13, 2026. No individual claimant bellwether trial date is set.

On May 28, 2025, the Utility executed an amendment to a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

On August 21, 2025, Cal Fire filed a complaint against the Utility for fire suppression and investigation costs.

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 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $350 million as of December 31, 2025 (before available recoveries). During the first quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $50 million for an aggregate liability of $400 million (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.
The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses50 
Payments(62)
Balance at March 31, 2026
$231 

As of March 31, 2026, the Utility recorded an insurance receivable of $416 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of March 31, 2026, the Utility also recorded a $7 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $54 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.
Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of March 31, 2026 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $416 
FERC TO rates
97 7 
WEMA
539 54 
Wildfire Fund
1,150 — 
Probable recoveries at March 31, 2026 (1)
$2,307 $477 
(1) Includes legal costs of $152 million and $76 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of March 31, 2026.

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Insurance
Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.
Insurance Receivable

As of March 31, 2026, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $521 million and $416 million in connection with the 2021 Dixie fire and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.
The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2025:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2025
$1 $281 $282 
Accrued insurance recoveries
— 53 53 
Reimbursements
— (73)(73)
Balance at March 31, 2026
$1 $261 $262 
Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire.

FERC TO Rates

The Utility recognizes income subject to potential refunds through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to FERC transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on an order from the FERC approving an all-party settlement in the TO21 rate case, as of March 31, 2026, the Utility recorded reductions of $97 million and $7 million regarding the 2021 Dixie fire and the 2022 Mosquito fire, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of March 31, 2026, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery, and the Utility recorded $539 million and $54 million, respectively, as regulatory assets in the WEMA.
Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 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. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. 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 arising from wildfires in any coverage 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. The accrued Wildfire Fund receivable as of March 31, 2026 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $5.1 billion for 2026. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2026 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution 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 failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to 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. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. 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. On March 2, 2026, the OEIS approved the Utility’s 2025 application and issued the Utility’s 2025 safety certification.

The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

AB 1054 authorizes the payment of funds to a participating utility where that utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.
PG&E Corporation and the Utility’s Wildfire Fund recoveries are reflected in Wildfire-related claims, net of recoveries in the Condensed Consolidated Statements of Income to the extent PG&E Corporation and the Utility determine that it is probable the CPUC will conclude that the Utility’s conduct was just and reasonable or when the Utility is not otherwise required to reimburse the Wildfire Fund.

As of March 31, 2026, PG&E Corporation and the Utility recorded $251 million and $7 million in Accounts receivable - Other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2025
$299 
Accrued Wildfire Fund recoveries— 
Claims paid by Wildfire Fund(41)
Balance at March 31, 2026
$258 

For more information, see Note 2 above.
Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount due to the number of plaintiffs and the complexity of the litigation.
Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act 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, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed the Public Employee Retirement Association of New Mexico (“PERA”) as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain 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 was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged 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. 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 certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. On February 26, 2026, the District Court entered an order preliminarily approving the settlement and scheduled the settlement approval hearing for August 25, 2026. Putative class members would have the right to opt out of the proposed settlement.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation. In April 2026, PG&E Corporation and the Utility settled with this group of shareholders. On April 22, 2026, the shareholders filed a request for dismissal pursuant to that settlement agreement, and the District Court terminated the case.
Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and proceeds from any insurance 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 any such allowed 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 engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those 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 Emergence 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 Emergence Date. To the extent any such claims are allowed, such claims could result in (a) the issuance of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of cash with respect to allowed Subordinated Debt Claims.
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 such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims, including prosecuting omnibus objections with respect to certain of the Subordinated Claims as necessary.
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 may extend to the claims asserted against certain directors and officers in the securities class actions.

PG&E Corporation and the Utility additionally may have 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, among other things.
OTHER CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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 and the Utility 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’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.
Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.
On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.
Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. In 2024, PG&E Corporation decreased its Income tax benefit by $70 million after the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.
Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Estimated liabilities for contingencies related to such matters totaled $145 million and $78 million as of March 31, 2026 and 2025, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10 above. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.
Environmental Remediation Contingencies

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. 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 the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Topock natural gas compressor station$301 $315 
Hinkley natural gas compressor station96 99 
Former MGP sites owned by the Utility or third parties (1)
867 715 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
75 71 
Fossil fuel-fired generation facilities and sites (3)
17 17 
Total environmental remediation liability$1,356 $1,217 
(1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street.
(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 MGP 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 United States Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.

The Utility’s environmental remediation liability as of March 31, 2026, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. 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.  As of March 31, 2026, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available.
 
Balance at March 31, 2026
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$301 $498 Available
Hinkley natural gas compressor station (2)
96 218 Unavailable
Former MGP sites owned by the Utility or third parties (3)
867 1,400 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
75 151 Available
Fossil fuel-fired generation facilities and sites (5)
17 30 Unavailable
(1) For sites where HSMA recovery is available, the Utility expects to recover 90% of the costs associated with environmental remediation through rates.
(2) 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. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years.
(3) 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.
(4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation.
(5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site.
Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

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 DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for DCPP. For the Humboldt Bay independent spent fuel storage installation, 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 and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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 $44 million.  For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.
Purchase Commitments
In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2025, the Utility had undiscounted future expected obligations of approximately $33 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS
 3 Months Ended
Mar. 31, 2026
Commitments and Contingencies Disclosure [Abstract]  
OTHER CONTINGENCIES AND COMMITMENTS WILDFIRE-RELATED CONTINGENCIES
Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that 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 record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.
Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, 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.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities.

The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest, and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages, and other damages under other theories of liability in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.
The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. Claims related to the 2019 Kincade fire are subject to the 40% limitation on the allowed amount of 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 the possession of Cal Fire, USFS, or the relevant district attorney’s office, 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.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through March 31, 2026.
Payments (in millions)
2019 Kincade Fire
$1,318 
2021 Dixie Fire2,009 
2022 Mosquito Fire169 
Total at March 31, 2026
$3,496 
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged.

On July 16, 2020, Cal Fire issued a press release with its determination that the Utility’s equipment caused the 2019 Kincade fire.

As of April 15, 2026, PG&E Corporation and the Utility have settled or reached settlements in principle with substantially all known individual plaintiffs.

In October 2022, the Utility entered into a tolling agreement with Cal OES, extending their time to file a complaint.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $1.325 billion as of December 31, 2025 (before available insurance). The aggregate liability remained unchanged as of March 31, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses represent the best estimate of the liability and do not include any claims related to Cal OES.

The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$38 
Accrued Losses— 
Payments(31)
Balance at March 31, 2026
$7 

The Utility has fully collected its liability insurance coverage for third-party liability attributable to the 2019 Kincade fire, which was for an aggregate amount of $430 million.

As of March 31, 2026, the Utility had received $115 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below.
2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, through its ongoing investigation, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in the Utility’s proceeding for review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire under AB 1054 or a future cost recovery proceeding may argue the Cal Fire Investigation Report itself creates serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe the report identifies sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of April 15, 2026, PG&E Corporation and the Utility are aware of approximately 190 complaints on behalf of at least 9,062 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A trial with respect to one plaintiff has been scheduled for December 2, 2026. The court has scheduled and vacated numerous bellwether trial dates, including the previously scheduled bellwether trial date of June 23, 2025. No bellwether trial is scheduled. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. One request for the court to set a damages-only trial is pending; the court has vacated all other previously scheduled damages-only trial dates.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. The Utility filed an amended answer to the complaint on September 30, 2024. On October 10, 2024, Cal Fire filed a demurrer and motion to strike portions of the amended answer. On February 7, 2025, the court issued a ruling sustaining Cal Fire’s demurrer and striking portions of the Utility’s amended answer. On April 7, 2025, the Utility filed a petition for writ of mandate in the California First District Court of Appeal, seeking an order directing the trial court to reverse the ruling on Cal Fire’s demurrer and motion to strike. On April 30, 2025, in response to the Court of Appeal’s request, Cal Fire filed an opposition to the Utility’s writ. The Utility filed a reply to the opposition on May 9, 2025. On February 13, 2026, the Court of Appeal denied the writ without opinion. The Utility filed a petition for review with the California Supreme Court, and on April 22, 2026, the California Supreme Court granted the petition for review and transferred the matter back to the Court of Appeal, with directions to vacate its order denying mandate and to issue an order to show cause why the relief sought in the petition should not be granted.

In February 2023, the Utility entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

PG&E Corporation and the Utility are aware of a separate putative class complaint, primarily seeking relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, and the hearing date on the motion is scheduled for July 8, 2026.
Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $2.15 billion as of December 31, 2025 (before available recoveries). The aggregate liability remained unchanged as of March 31, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.15 billion do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by federal or state agencies other than Cal Fire, including for fire suppression costs and damages related to federal land, (iv) class action medical monitoring costs, or (v) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2021 Dixie fire does not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses— 
Payments(101)
Balance at March 31, 2026
$142 

As of March 31, 2026, the Utility recorded an insurance receivable of $521 million for probable insurance recoveries in connection with the 2021 Dixie fire.

The Utility recorded an aggregate Wildfire Fund receivable of $1.15 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $892 million as of March 31, 2026. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of March 31, 2026, the Utility also recorded a $97 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $539 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below. Decreases in the amount of the insurance receivable for the 2021 Dixie fire may also increase the amount that is probable of recovery through the FERC TO formula rate and the WEMA.
2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS, the United States Department of Justice, and the CPUC. PG&E Corporation and the Utility are cooperating with the investigations. 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 2022 Mosquito fire. This investigation is ongoing.

As of April 15, 2026, PG&E Corporation and the Utility are aware of approximately 30 complaints on behalf of at least 2,931 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and the Regents of the University of California have each filed a complaint. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into a settlement agreement with five public entities, and their complaint was dismissed on February 4, 2026. In April 2026, PG&E Corporation and the Utility entered into a settlement agreement with PCWA and Middle Fork Project Finance Authority. The court vacated the previously scheduled individual claimant bellwether trial date for April 13, 2026. No individual claimant bellwether trial date is set.

On May 28, 2025, the Utility executed an amendment to a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

On August 21, 2025, Cal Fire filed a complaint against the Utility for fire suppression and investigation costs.

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 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $350 million as of December 31, 2025 (before available recoveries). During the first quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $50 million for an aggregate liability of $400 million (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.
The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses50 
Payments(62)
Balance at March 31, 2026
$231 

As of March 31, 2026, the Utility recorded an insurance receivable of $416 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of March 31, 2026, the Utility also recorded a $7 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $54 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.
Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2019 Kincade Fire,” “2021 Dixie Fire,” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of March 31, 2026 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $416 
FERC TO rates
97 7 
WEMA
539 54 
Wildfire Fund
1,150 — 
Probable recoveries at March 31, 2026 (1)
$2,307 $477 
(1) Includes legal costs of $152 million and $76 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of March 31, 2026.

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Insurance
Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.
Insurance Receivable

As of March 31, 2026, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $521 million and $416 million in connection with the 2021 Dixie fire and the 2022 Mosquito fire, respectively. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.
The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2025:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2025
$1 $281 $282 
Accrued insurance recoveries
— 53 53 
Reimbursements
— (73)(73)
Balance at March 31, 2026
$1 $261 $262 
Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire.

FERC TO Rates

The Utility recognizes income subject to potential refunds through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to FERC transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on an order from the FERC approving an all-party settlement in the TO21 rate case, as of March 31, 2026, the Utility recorded reductions of $97 million and $7 million regarding the 2021 Dixie fire and the 2022 Mosquito fire, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of March 31, 2026, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery, and the Utility recorded $539 million and $54 million, respectively, as regulatory assets in the WEMA.
Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 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. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. 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 arising from wildfires in any coverage 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. The accrued Wildfire Fund receivable as of March 31, 2026 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a disallowance cap equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the disallowance cap in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the disallowance cap would be approximately $5.1 billion for 2026. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2026 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution 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 failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to 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. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. 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. On March 2, 2026, the OEIS approved the Utility’s 2025 application and issued the Utility’s 2025 safety certification.

The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

AB 1054 authorizes the payment of funds to a participating utility where that utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.
PG&E Corporation and the Utility’s Wildfire Fund recoveries are reflected in Wildfire-related claims, net of recoveries in the Condensed Consolidated Statements of Income to the extent PG&E Corporation and the Utility determine that it is probable the CPUC will conclude that the Utility’s conduct was just and reasonable or when the Utility is not otherwise required to reimburse the Wildfire Fund.

As of March 31, 2026, PG&E Corporation and the Utility recorded $251 million and $7 million in Accounts receivable - Other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire. The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2025
$299 
Accrued Wildfire Fund recoveries— 
Claims paid by Wildfire Fund(41)
Balance at March 31, 2026
$258 

For more information, see Note 2 above.
Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility face certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the PSPS program in the Chapter 11 Cases (i.e., the Subordinated Claims), and certain former directors, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation believes it is probable that it will incur a loss in connection with these matters. PG&E Corporation has recorded a liability in the aggregate amount of $300 million, which represents its best estimate of probable losses for the Wildfire-Related Securities Claims. PG&E Corporation believes that it is reasonably possible that the amount of loss could be greater or less than the accrued estimated amount due to the number of plaintiffs and the complexity of the litigation.
Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act 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, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed the Public Employee Retirement Association of New Mexico (“PERA”) as lead plaintiff. PERA filed a consolidated amended complaint on November 9, 2018. On December 14, 2018, PERA filed a second amended consolidated complaint to add allegations regarding the 2018 Camp fire, including allegations regarding transmission line safety and the PSPS program.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain 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 was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged 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. 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 certain former officers and directors and the underwriters. While PG&E Corporation and the Utility are also named as defendants, the claims against PG&E Corporation and the Utility may only be pursued in Bankruptcy Court. On October 24, 2024, the officer, director, and underwriter defendants filed renewed motions to dismiss the third amended complaint. On September 30, 2025, the District Court granted the motions to dismiss with leave to amend. On November 14, 2025, the plaintiffs filed a fourth amended consolidated class action complaint. On December 22, 2025, the officer, director, and underwriter defendants filed motions to dismiss the fourth amended complaint.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. The proposed settlement is subject to District Court approval. On February 26, 2026, the District Court entered an order preliminarily approving the settlement and scheduled the settlement approval hearing for August 25, 2026. Putative class members would have the right to opt out of the proposed settlement.

On March 21, 2023, another group of shareholders filed a separate action in the District Court against certain former officers and directors, entitled Orbis Capital Limited et al., v. Williams et al., alleging similar claims to those alleged in In re PG&E Corporation Securities Litigation. In April 2026, PG&E Corporation and the Utility settled with this group of shareholders. On April 22, 2026, the shareholders filed a request for dismissal pursuant to that settlement agreement, and the District Court terminated the case.
Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

PG&E Corporation and the Utility intend to resolve securities claims filed in the bankruptcy consistent with the Plan. These claims consist of pre-petition claims against PG&E Corporation or the Utility 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 United States Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the trading of 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 the trading of 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, these defenses may not prevail and proceeds from any insurance 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 any such allowed 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 engaged in settlement efforts with respect to the Subordinated Claims. All such settlements have been conditioned upon, among other things, resolution of that claimant’s Wildfire-Related Non-Bankruptcy Securities Claims. If any of the Subordinated Claims are ultimately not settled, PG&E Corporation and the Utility expect that those 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 Emergence 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 Emergence Date. To the extent any such claims are allowed, such claims could result in (a) the issuance of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of cash with respect to allowed Subordinated Debt Claims.
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 such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Emergence Date, assuming that such issuance of shares in satisfaction of the HoldCo Rescission or Damage Claims had occurred on the Emergence Date.

On January 25, 2021, the Bankruptcy Court issued an order to approve procedures to help facilitate the resolution of the Subordinated Claims. The order, among other things, established procedures allowing PG&E Corporation and the Utility to collect trading information with respect to the Subordinated Claims, to engage in an alternative dispute resolution process for resolving disputed Subordinated Claims, and to file certain omnibus claim objections with respect to the Subordinated Claims.

PG&E Corporation and the Utility have worked to resolve the Subordinated Claims in accordance with procedures approved by the Bankruptcy Court, including by collecting trading information from holders of Subordinated Claims. Also, pursuant to those procedures, PG&E Corporation and the Utility have filed numerous omnibus objections in the Bankruptcy Court to certain of the Subordinated Claims. The Bankruptcy Court has entered several orders disallowing and expunging Subordinated Claims that were subject to these omnibus objections, and certain Subordinated Claims subject to these omnibus objections remain pending. PG&E Corporation and the Utility expect to continue to act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims, including prosecuting omnibus objections with respect to certain of the Subordinated Claims as necessary.
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 may extend to the claims asserted against certain directors and officers in the securities class actions.

PG&E Corporation and the Utility additionally may have 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, among other things.
OTHER CONTINGENCIES AND COMMITMENTS
PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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 and the Utility 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’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.
Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.
On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the interim rate relief being subject to refund.
Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. In 2024, PG&E Corporation decreased its Income tax benefit by $70 million after the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.
Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material.  Estimated liabilities for contingencies related to such matters totaled $145 million and $78 million as of March 31, 2026 and 2025, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10 above. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.
Environmental Remediation Contingencies

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. 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 the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Topock natural gas compressor station$301 $315 
Hinkley natural gas compressor station96 99 
Former MGP sites owned by the Utility or third parties (1)
867 715 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
75 71 
Fossil fuel-fired generation facilities and sites (3)
17 17 
Total environmental remediation liability$1,356 $1,217 
(1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street.
(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 MGP 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 United States Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances.  The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.

The Utility’s environmental remediation liability as of March 31, 2026, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. 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.  As of March 31, 2026, the Utility expected to recover $1.1 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available.
 
Balance at March 31, 2026
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$301 $498 Available
Hinkley natural gas compressor station (2)
96 218 Unavailable
Former MGP sites owned by the Utility or third parties (3)
867 1,400 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
75 151 Available
Fossil fuel-fired generation facilities and sites (5)
17 30 Unavailable
(1) For sites where HSMA recovery is available, the Utility expects to recover 90% of the costs associated with environmental remediation through rates.
(2) 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. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years.
(3) 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.
(4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation.
(5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site.
Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

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 DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for DCPP. For the Humboldt Bay independent spent fuel storage installation, 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 and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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 $44 million.  For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.
Purchase Commitments
In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. As of December 31, 2025, the Utility had undiscounted future expected obligations of approximately $33 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.
v3.26.1
Insider Trading Arrangements
 3 Months Ended
Mar. 31, 2026
shares
Trading Arrangements, by Individual  
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
Marlene Santos [Member]  
Trading Arrangements, by Individual  
Material Terms of Trading Arrangement
On March 11, 2026, Marlene Santos, who serves as the Executive Vice President, Enterprise Transformation Office of PG&E Corporation and Pacific Gas and Electric Company, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) under the Exchange Act, for the sale of an indeterminate number of shares of PG&E Corporation common stock. The number of shares that may be sold under this Rule 10b5-1 trading arrangement will vary based on the number of shares that Ms. Santos receives when her performance share units (“PSUs”) vest. Assuming that the PSUs vest at 100% of target, this Rule 10b5-1 plan would entail the sale of 374,428 shares, but the actual number could vary based on the number of PSUs that vest. In addition, the maximum number of shares to be sold will be reduced by shares withheld to satisfy tax withholding obligations that arise in connection with the vesting and settlement. The trading arrangement will terminate on the earlier of December 31, 2027 or the execution of the sale of all covered shares.
Name Marlene Santos
Title Executive Vice President, Enterprise Transformation Office of PG&E Corporation and Pacific
Rule 10b5-1 Arrangement Adopted true
Adoption Date March 11, 2026
Expiration Date December 31, 2027
Arrangement Duration 660 days
Aggregate Available 374,428
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 3 Months Ended
Mar. 31, 2026
Accounting Policies [Abstract]  
Segment Reporting
Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker (“CODM”) is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the CODM uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Condensed Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the CODM is not regularly provided with information that is considered to be significant under Accounting Standards Codification (“ASC”) 280, Segment Reporting. Except for publicly available information, the information regularly provided to the CODM consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.
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 Condensed Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

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

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of March 31, 2026, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses using an analysis of regional unemployment rates.

Expected credit losses of $89 million and $100 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables during the three months ended March 31, 2026 and 2025, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of March 31, 2026, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $60 million and $88 million, respectively. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. The RUBA current balancing account balance decreased from December 31, 2025 to March 31, 2026 primarily due to the annual electric and gas rate true-up, which allows the Utility to recover approximately $278 million in undercollections from residential customers in 2026.
Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of March 31, 2026, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Government Assistance
Government Assistance

The Utility participated in various government assistance programs during the three months ended March 31, 2026 and 2025. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).
DWR Loan Agreement

On October 18, 2022, the DWR and the Utility entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final proceeds were received in 2024, and no further disbursements will be made.

The Utility initially accounted for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:
Three Months Ended March 31,
(in millions)
20262025
Long-term debt:
Beginning Balance - DWR loan outstanding
$738 $886 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
— (8)
Operating and maintenance expense - Loan forgiveness and other adjustments
(4)(57)
Other current liabilities:
Change in performance-based disbursements deferred
— (9)
Long-term debt:
Ending Balance - DWR loan outstanding$734 $812 
U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and the DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the three months ended March 31, 2026 and 2025, the Condensed Consolidated Statements of Income reflected $10 million and $40 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three months ended March 31, 2026, the amount recorded as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP was immaterial to the Condensed Consolidated Statements of Income. During the three months ended March 31, 2025, the Condensed Consolidated Statements of Income reflected $41 million as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP.
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 VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Condensed Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. As of March 31, 2026 and December 31, 2025, the SPV had net accounts receivable of $2.9 billion and $3.2 billion, respectively, and outstanding borrowings of $1.8 billion, under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate Recovery Property.
PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of March 31, 2026 and December 31, 2025, PG&E Recovery Funding LLC had outstanding borrowings of $3.0 billion and $3.1 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the three months ended March 31, 2026 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate of $7.5 billion of senior secured recovery bonds. As of March 31, 2026 and December 31, 2025, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs as of March 31, 2026, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of March 31, 2026, it did not consolidate any of them.
Pension and Other Post-Retirement Benefits
Pension and Other Post-Retirement Benefits

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.
Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted
Recently Adopted Accounting Standards

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU became effective for PG&E Corporation and the Utility on January 1, 2026. The adoption of this ASU did not have an immediate impact and is not expected to have a significant impact in future periods on PG&E Corporation and the Utility’s Condensed Consolidated Financial Statements and related disclosures.
Accounting Standards Issued But Not Yet Adopted

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amended the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
Intangibles – Goodwill and Other – Internal Use Software
In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40), which amended the existing guidance to modernize the accounting for software costs that are accounted for under Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this ASU remove all references to prescriptive and sequential software development stages throughout Subtopic 350-40. Therefore, an entity is required to start capitalizing software costs when both of the following occur: (1) management has authorized and committed to funding the software project, and (2) it is probable that the project will be completed, and the software will be used to perform the function. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
Earnings Per Share PG&E Corporation’s basic EPS is calculated by dividing the Income available for common shareholders, basic, by the weighted average number of common shares outstanding, basic. PG&E Corporation’s diluted EPS is calculated by dividing the income available for common shareholders, diluted, by the weighted average number of common shares outstanding, diluted.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Condensed 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 Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed 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 Condensed Consolidated Balance Sheets at fair value.
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)
 3 Months Ended
Mar. 31, 2026
Accounting Policies [Abstract]  
Summary of Revenues Disaggregated by Type of Customer
The following table presents the Utility’s revenues disaggregated by type of customer:
Three Months Ended March 31,
(in millions)20262025
Electric
Revenue from contracts with customers
   Residential$1,807 $1,834 
   Commercial1,592 1,506 
   Industrial438 414 
   Agricultural205 199 
   Public street and highway lighting26 27 
   Other, net (1)
293 89 
Total revenue from contracts with customers - electric4,361 4,069 
Regulatory balancing accounts (2)
606 66 
Total electric operating revenue$4,967 $4,135 
Natural gas
Revenue from contracts with customers
   Residential$1,480 $1,709 
   Commercial368 399 
   Transportation service only490 546 
   Other, net (1)
(322)(120)
Total revenue from contracts with customers - gas2,016 2,534 
Regulatory balancing accounts (2)
(102)(686)
Total natural gas operating revenue1,914 1,848 
Total operating revenues$6,881 $5,983 
(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 alternative revenues authorized to be billed or refunded to customers.
Schedule Of Government Assistance
The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:
Three Months Ended March 31,
(in millions)
20262025
Long-term debt:
Beginning Balance - DWR loan outstanding
$738 $886 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
— (8)
Operating and maintenance expense - Loan forgiveness and other adjustments
(4)(57)
Other current liabilities:
Change in performance-based disbursements deferred
— (9)
Long-term debt:
Ending Balance - DWR loan outstanding$734 $812 
Schedule of Net Benefit Costs
The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2026 and 2025 were as follows:
Pension BenefitsOther Benefits
Three Months Ended March 31,
(in millions)2026202520262025
Service cost for benefits earned (1)
$115 $106 $11 $9 
Interest cost256 252 20 18 
Expected return on plan assets(307)(263)(39)(37)
Amortization of prior service cost (credit)(1)(1)1 1 
Amortization of net actuarial loss (gain)1 — (4)(6)
Net periodic benefit cost64 94 (11)(15)
Regulatory account transfer (2)
20 (10)— — 
Total$84 $84 $(11)$(15)
(1) A portion of service costs is capitalized pursuant to GAAP.
(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery or refund through rates in future periods.
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) consisted of the following:
Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
(in millions, net of income tax)Three Months Ended March 31, 2026
Beginning balance$(47)$19 $8 $(20)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $3, respectively)
— — (6)(6)
Amounts reclassified from other comprehensive income: (1)
Amortization of net actuarial gain (net of taxes of $0, $1, and $0, respectively)
— (2)— (2)
Regulatory account transfer (net of taxes of $0, $1, and $0, respectively)
— 2 — 2 
Net current period other comprehensive (loss)— — (6)(6)
Ending balance$(47)$19 $2 $(26)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and self-insurance.
Pension BenefitsOther
Benefits
Available-for-Sale Securities(2)
Total
(in millions, net of income tax)Three Months Ended March 31, 2025
Beginning balance$(35)$18 $3 $(14)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0, and $2 respectively)
— — 7 7 
Amounts reclassified from other comprehensive income: (1)
Amortization of net actuarial gain (net of taxes of $0, $1, and $0, respectively)
— (4)— (4)
Regulatory account transfer (net of taxes of $0, $1, and $0, respectively)
— 4 — 4 
Net current period other comprehensive gain— — 7 7 
Ending balance$(35)$18 $10 $(7)
(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs.  See the “Pension and Other Post-Retirement Benefits” table above for additional details.
(2) Includes amounts related to the customer credit trust and Pacific Energy Risk Solutions, LLC.
v3.26.1
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)
 3 Months Ended
Mar. 31, 2026
Regulated Operations [Abstract]  
Long-Term Regulatory Assets
Noncurrent regulatory assets are comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Pension benefits
$381 $400 
Environmental compliance costs1,140 1,158 
Price risk management97 100 
Catastrophic event memorandum account
466 666 
Wildfire-related accounts
1,360 1,626 
Deferred income taxes6,460 6,157 
Financing costs199 202 
SB 901 securitization
5,058 5,089 
Other561 583 
Total noncurrent regulatory assets$15,722 $15,981 
Long-Term Regulatory Liabilities
Noncurrent regulatory liabilities are comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Cost of removal obligations
$9,680 $9,488 
Public purpose programs
1,203 1,169 
Employee benefit plans
1,049 1,043 
Transmission tower wireless licenses
254 257 
SB 901 securitization
5,898 6,010 
Wildfire self-insurance
1,041 1,035 
Other1,140 1,186 
Total noncurrent regulatory liabilities
$20,265 $20,188 
Current Regulatory Balancing Accounts Receivable
Current regulatory balancing accounts receivable and payable are comprised of the following:
Balance at
(in millions)March 31, 2026December 31, 2025
Electric distribution
$2,796 $1,465 
Electric transmission
133 122 
Gas distribution and transmission
89 142 
Energy procurement
1,184 2,711 
Public purpose programs
258 151 
Wildfire-related accounts
71 84 
Residential uncollectibles balancing accounts
60 278 
Catastrophic event memorandum account
27 181 
Other407 1,166 
Total regulatory balancing accounts receivable$5,025 $6,300 
Current Regulatory Balancing Accounts Payable
Balance at
(in millions)March 31, 2026December 31, 2025
Electric transmission
$9 $37 
Gas distribution and transmission
92 78 
Energy procurement
75 1,502 
Public purpose programs
492 472 
SFGO sale20 83 
Wildfire-related accounts
420 338 
Nuclear decommissioning adjustment mechanism
1 1 
Other487 608 
Total regulatory balancing accounts payable$1,596 $3,119 
v3.26.1
DEBT (Tables)
 3 Months Ended
Mar. 31, 2026
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 as of March 31, 2026:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facility June 2030$5,400 
(1)
$(575)$(291)$4,534 
Utility Receivables Securitization Program (2)
June 20271,750 
(3)
(1,750)— — 
(3)
PG&E Corporation revolving credit facilityJune 2028650 — — 650 
Total credit facilities$7,800 $(2,325)$(291)$5,184 
(1) Includes a $2.0 billion letter of credit sublimit.
(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.
(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
v3.26.1
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Tables)
 3 Months Ended
Mar. 31, 2026
Debt Disclosure [Abstract]  
Schedule of Financial Statement Impact of Securitization
The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:
SB 901 securitization regulatory asset
(in millions)
20262025
Balance at January 1
$5,089 $5,194 
Amortization
(31)(19)
Balance at March 31
$5,058 $5,175 

SB 901 securitization regulatory liability
(in millions)
20262025
Balance at January 1$(6,010)$(6,295)
Amortization
11393
Additions(1)
(1)(1)
Balance at March 31
$(5,898)$(6,203)
(1) Includes $1 million of returns on investments in the customer credit trust expected to be credited to customers for each of the three months ended March 31, 2026 and 2025.
v3.26.1
EQUITY (Tables)
 3 Months Ended
Mar. 31, 2026
Equity [Abstract]  
Schedule of Dividend Paid on Common Stock
The following table summarizes the dividends paid or declared by PG&E Corporation and the Utility in 2026:

SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation common stock$0.05 $110 December 11, 2025December 31, 2025January 15, 2026
0.05111 February 19, 2026March 31, 2026April 15, 2026
Utility common stock
(1)
625 February 19, 2026
(1)
March 30, 2026
PG&E Corporation mandatory convertible preferred stock0.7524 December 11, 2025February 13, 2026March 1, 2026
0.75 24 February 19, 2026May 15, 2026June 1, 2026
Utility preferred stockvaries by series3.5 December 11, 2025January 30, 2026February 15, 2026
varies by series3.5 February 19, 2026April 30, 2026May 15, 2026
(1) PG&E Corporation owns all of the outstanding shares of the Utility’s common stock.
v3.26.1
EARNINGS PER SHARE (Tables)
 3 Months Ended
Mar. 31, 2026
Earnings Per Share [Abstract]  
Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:
Three Months Ended March 31,
(in millions, except per share amounts)20262025
Numerator:
Income available for common shareholders, basic$858 $607 
Mandatory Convertible Preferred Stock dividends24 — 
Income available for common shareholders, diluted$882 $607 
Denominator:
Weighted average common shares outstanding, basic(1)
2,199 2,195 
Dilutive effect of Employee stock-based compensation4 5 
Dilutive effect of Mandatory Convertible Preferred Stock78 — 
Weighted average common shares outstanding, diluted2,281 2,200 
Total income per common share:
Basic$0.39 $0.28 
Diluted$0.39 $0.28 
(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.
v3.26.1
DERIVATIVES (Tables)
 3 Months Ended
Mar. 31, 2026
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Volumes of Outstanding Derivative Contracts
The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume at
Underlying ProductInstrumentsMarch 31, 2026December 31, 2025
Natural Gas (1) (MMBtus (2))
Forwards, futures, and swaps204,557,995 232,825,834 
 Options34,175,000 48,215,000 
Electricity (MWh)Forwards, futures, and swaps6,903,828 7,196,942 
Options2,678,000 1,650,800 
 
Congestion Revenue Rights (3)
83,584,734 93,712,644 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Offsetting Liabilities
As of March 31, 2026, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$152 $(28)$19 $143 
Noncurrent assets – other156 (2)— 154 
Current liabilities – other(103)28 11 (64)
Noncurrent liabilities – other(99)2 — (97)
Total commodity risk$106 $— $30 $136 

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$165 $(46)$— $119 
Noncurrent assets – other170 (6)— 164 
Current liabilities – other(169)46 — (123)
Noncurrent liabilities – other(106)6 — (100)
Total commodity risk$60 $— $— $60 
Offsetting Assets
As of March 31, 2026, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$152 $(28)$19 $143 
Noncurrent assets – other156 (2)— 154 
Current liabilities – other(103)28 11 (64)
Noncurrent liabilities – other(99)2 — (97)
Total commodity risk$106 $— $30 $136 

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingCash CollateralTotal Derivative
Balance
Current assets – other$165 $(46)$— $119 
Noncurrent assets – other170 (6)— 164 
Current liabilities – other(169)46 — (123)
Noncurrent liabilities – other(106)6 — (100)
Total commodity risk$60 $— $— $60 
v3.26.1
FAIR VALUE MEASUREMENTS (Tables)
 3 Months Ended
Mar. 31, 2026
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 March 31, 2026
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments
$1,016 $— $— $— $1,016 
Self-insurance investments
   Short-term investments1,178 — — — 1,178 
Total Self-insurance investments (2)
1,178 — — — 1,178 
Nuclear decommissioning trusts
Short-term investments53 — — — 53 
Global equity securities2,336 — — — 2,336 
Fixed-income securities1,518 1,107 — — 2,625 
Assets measured at NAV— — — — 25 
Total nuclear decommissioning trusts (3)
3,907 1,107 — — 5,039 
Customer credit trust
Short-term investments127 — — — 127 
Global equity securities— — — — — 
Fixed-income securities178 386 — — 564 
Total customer credit trust
305 386 — — 691 
Price risk management instruments (Note 8)
     
Electricity— 31 260 (9)282 
Gas— 17 — (2)15 
Total price risk management instruments— 48 260 (11)297 
Rabbi trusts     
Short-term investments117 — — — 117 
Global equity securities5 — — — 5 
Life insurance contracts— 65 — — 65 
Total rabbi trusts122 65 — — 187 
Long-term disability trust     
Short-term investments1 — — — 1 
Assets measured at NAV— — — — 127 
Total long-term disability trust1 — — — 128 
TOTAL ASSETS$6,529 $1,606 $260 $(11)$8,536 
Liabilities:     
Price risk management instruments (Note 8)
     
Electricity$— $31 $168 $(39)$160 
Gas— 3 — (2)1 
TOTAL LIABILITIES$— $34 $168 $(41)$161 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Includes approximately $1 billion and $119 million held in the entities for wildfire and non-wildfire self-insurance, respectively.
(3) Represents amount before deducting $854 million primarily related to deferred taxes on appreciation of investment value.
 Fair Value Measurements
 
At December 31, 2025
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$634 $— $— $— $634 
Self-insurance investments
    Short-term investments1,120 — — — 1,120 
Total Self-insurance investments(2)
1,120 — — — 1,120 
Nuclear decommissioning trusts
Short-term investments94 — — — 94 
Global equity securities2,433 — — — 2,433 
Fixed-income securities1,445 1,113 — — 2,558 
Assets measured at NAV— — — — 26 
Total nuclear decommissioning trusts (3)
3,972 1,113 — — 5,111 
Customer credit trust
Short-term investments111 — — — 111 
Global equity securities— — — — 
Fixed-income securities367 326 — — 693 
Total customer credit trust
478 326 — — 804 
Price risk management instruments (Note 8)
    
Electricity— 19 283 (6)296 
Gas— 33 — (46)(13)
Total price risk management instruments— 52 283 (52)283 
Rabbi trusts    
Short-term investments115 — — — 115 
Global equity securities5 — — — 5 
Life insurance contracts— 65 — — 65 
Total rabbi trusts120 65 — — 185 
Long-term disability trust    
Short-term investments10 — — — 10 
Assets measured at NAV— — — — 127 
Total long-term disability trust10 — — — 137 
TOTAL ASSETS$6,334 $1,556 $283 $(52)$8,274 
Liabilities:    
Price risk management instruments (Note 8)
    
Electricity$— $80 $130 $(6)$204 
Gas— 65 — (46)19 
TOTAL LIABILITIES$— $145 $130 $(52)$223 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Includes $1 billion and $77 million held in the entities for wildfire and non-wildfire self-insurance, respectively.
(3) Represents amount before deducting $881 million primarily related to deferred taxes on appreciation of investment value.
Fair Value Measurement Inputs and Valuation Techniques
 Fair Value
(in millions)		   
At March 31, 2026Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$229 $75 Market approachCRR auction prices
$ (79) - 74 / 2
Power purchase agreements$31 $93 Discounted cash flowForward prices
$ 10 - 102 / 51
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

 Fair Value
(in millions)		   
At December 31, 2025Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$252 $83 Market approachCRR auction prices
$ (74) - 74 / 2
Power purchase agreements$31 $47 Discounted cash flowForward prices
$ 11 - 106 / 53
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2026 and 2025:
 Price Risk Management Instruments
(in millions)20262025
Asset balance as of January 1$153 $127 
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)
(61)(1)
Asset balance as of March 31$92 $126 
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets, and net income is not impacted.
Carrying Amount and Fair Value of Financial Instruments
The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
 
At March 31, 2026
At December 31, 2025
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount
Level 2 Fair Value
Debt (Note 4)    
PG&E Corporation (1)
$6,326 $6,715 $5,360 $5,697 
Utility41,887 38,779 38,145 35,565 
(1) As of March 31, 2026, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.1 billion and $2.2 billion, respectively.
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 March 31, 2026
    
Nuclear decommissioning trusts    
Short-term investments$53 $— $— $53 
Global equity securities323 2,045 (7)2,361 
Fixed-income securities2,647 30 (52)2,625 
Total (1)
$3,023 $2,075 $(59)$5,039 
As of December 31, 2025    
Nuclear decommissioning trusts    
Short-term investments$94 $— $— $94 
Global equity securities324 2,140 (5)2,459 
Fixed-income securities2,557 48 (47)2,558 
Total (1)
$2,975 $2,188 $(52)$5,111 
(1) Represents amounts before deducting $854 million and $881 million as of March 31, 2026 and December 31, 2025, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Available for Sale Securities Table
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)March 31, 2026
Less than 1 year$58 
1–5 years904 
5–10 years592 
More than 10 years1,071 
Total maturities of fixed-income securities$2,625 
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 March 31, 2026
Customer credit trust
Short-term investments$127 $— $— $127 
Global equity securities— — — — 
Fixed-income securities566 1 (3)564 
Total
$693 $1 $(3)$691 
As of December 31, 2025    
Customer credit trust    
Short-term investments$111 $— $— $111 
Global equity securities— — — — 
Fixed-income securities689 5 (1)693 
Total
$800 $5 $(1)$804 
Schedule of Activity for Debt and Equity Securities
The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended March 31,
(in millions)20262025
Proceeds from sales and maturities of nuclear decommissioning trust investments$400 $278 
Gross realized gains on securities21 2 
Gross realized losses on securities(8)(6)
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)March 31, 2026
Less than 1 year$22 
1–5 years354 
5–10 years51 
More than 10 years137 
Total maturities of fixed-income securities$564 
The following table provides a summary of activity for the fixed-income and equity securities:
Three Months Ended
March 31,
(in millions)20262025
Proceeds from sales and maturities of customer credit trust investments$116 $99 
Gross realized gains on securities5 3 
Gross realized losses on securities
(3)(3)
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Tables)
 3 Months Ended
Mar. 31, 2026
Commitments and Contingencies Disclosure [Abstract]  
Summary of Wildfire-Related Claims
The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through March 31, 2026.
Payments (in millions)
2019 Kincade Fire
$1,318 
2021 Dixie Fire2,009 
2022 Mosquito Fire169 
Total at March 31, 2026
$3,496 
The following table presents changes in the best estimate of PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2019 Kincade fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$38 
Accrued Losses— 
Payments(31)
Balance at March 31, 2026
$7 
The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses— 
Payments(101)
Balance at March 31, 2026
$142 
The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.
Loss Accrual (in millions)
Balance at December 31, 2025
$243 
Accrued Losses50 
Payments(62)
Balance at March 31, 2026
$231 
Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of March 31, 2026 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $416 
FERC TO rates
97 7 
WEMA
539 54 
Wildfire Fund
1,150 — 
Probable recoveries at March 31, 2026 (1)
$2,307 $477 
(1) Includes legal costs of $152 million and $76 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of March 31, 2026.
The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2021 Dixie fire and 2022 Mosquito fire since December 31, 2025:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2025
$1 $281 $282 
Accrued insurance recoveries
— 53 53 
Reimbursements
— (73)(73)
Balance at March 31, 2026
$1 $261 $262 
The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2025
$299 
Accrued Wildfire Fund recoveries— 
Claims paid by Wildfire Fund(41)
Balance at March 31, 2026
$258 
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Tables)
 3 Months Ended
Mar. 31, 2026
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Environmental Remediation Liability The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)March 31, 2026December 31, 2025
Topock natural gas compressor station$301 $315 
Hinkley natural gas compressor station96 99 
Former MGP sites owned by the Utility or third parties (1)
867 715 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
75 71 
Fossil fuel-fired generation facilities and sites (3)
17 17 
Total environmental remediation liability$1,356 $1,217 
(1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street.
(2) Primarily driven by Geothermal Landfill and Shell Pond site.
(3) Primarily driven by the San Francisco Potrero Power Plant.
The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available.
 
Balance at March 31, 2026
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$301 $498 Available
Hinkley natural gas compressor station (2)
96 218 Unavailable
Former MGP sites owned by the Utility or third parties (3)
867 1,400 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
75 151 Available
Fossil fuel-fired generation facilities and sites (5)
17 30 Unavailable
(1) For sites where HSMA recovery is available, the Utility expects to recover 90% of the costs associated with environmental remediation through rates.
(2) 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. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years.
(3) 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.
(4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation.
(5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site.
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Segment Reporting) (Narrative) (Details)
 3 Months Ended
Mar. 31, 2026
notice
Accounting Policies [Abstract]  
Number of reportable segments 1
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Revenue Recognition) (Narrative) (Details)
 3 Months Ended
Mar. 31, 2026
Accounting Policies [Abstract]  
Period for probable revenue recovery 24 months
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Revenues Disaggregated by Type of Customer) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Disaggregation of Revenue [Abstract]    
Total operating revenues $ 6,881 $ 5,983
Electric    
Disaggregation of Revenue [Abstract]    
Total operating revenues 4,967 4,135
Natural gas    
Disaggregation of Revenue [Abstract]    
Total operating revenues 1,914 1,848
Utility    
Disaggregation of Revenue [Abstract]    
Total operating revenues 6,881 5,983
Utility | Electric    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 4,361 4,069
Regulatory balancing accounts 606 66
Total operating revenues 4,967 4,135
Utility | Electric | Residential    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 1,807 1,834
Utility | Electric | Commercial    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 1,592 1,506
Utility | Electric | Industrial    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 438 414
Utility | Electric | Agricultural    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 205 199
Utility | Electric | Public street and highway lighting    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 26 27
Utility | Electric | Other, net    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 293 89
Utility | Natural gas    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 2,016 2,534
Regulatory balancing accounts (102) (686)
Total operating revenues 1,914 1,848
Utility | Natural gas | Residential    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 1,480 1,709
Utility | Natural gas | Commercial    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 368 399
Utility | Natural gas | Transportation service only    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers 490 546
Utility | Natural gas | Other, net    
Disaggregation of Revenue [Abstract]    
Total revenue from contracts with customers $ (322) $ (120)
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Financial Assets Measured at Amortized Cost – Credit Losses) (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Dec. 31, 2025
Public Utility, Property, Plant and Equipment [Line Items]      
Credit losses $ 89 $ 100  
Regulatory assets 15,722   $ 15,981
Regulatory Balancing Accounts Receivable      
Public Utility, Property, Plant and Equipment [Line Items]      
Total regulatory balancing accounts 5,025   6,300
FERC TO rates      
Public Utility, Property, Plant and Equipment [Line Items]      
Regulatory assets 88   92
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable      
Public Utility, Property, Plant and Equipment [Line Items]      
Total regulatory balancing accounts 60   $ 278
Decrease in regulatory balancing accounts $ 278    
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Government Assistance) (Details) - USD ($)
 3 Months Ended
Jan. 11, 2024
Oct. 18, 2022
Mar. 31, 2026
Mar. 31, 2025
Performance-Based Disbursement        
Public Utility, Property, Plant and Equipment [Line Items]        
Disbursement   $ 7    
Maximum disbursement   300,000,000    
Civil Nuclear Credit Program        
Public Utility, Property, Plant and Equipment [Line Items]        
Disbursement     $ 10,000,000 $ 40,000,000
Maximum disbursement $ 1,100,000,000      
Civil Nuclear Credit Program | Utilities Operating Expense, Maintenance and Operations        
Public Utility, Property, Plant and Equipment [Line Items]        
Reimbursement amount     $ 0 $ 41,000,000
Senate Bill 846 | Utility        
Public Utility, Property, Plant and Equipment [Line Items]        
Debt instrument, face amount   1,100,000,000    
Maximum | Senate Bill 846 | Utility        
Public Utility, Property, Plant and Equipment [Line Items]        
Debt instrument, face amount   $ 1,400,000,000    
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Schedule Of DWR Loan Activity) (Details) - DWR Loan - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Government Assistance, Liability [Roll Forward]    
Beginning balance $ 738 $ 886
Ending balance $ 734 $ 812
Government Assistance, Liability, Statement of Financial Position [Extensible Enumeration] Long-term debt (includes $11.6 billion and $11.7 billion related to VIEs at respective dates) Long-term debt (includes $11.6 billion and $11.7 billion related to VIEs at respective dates)
Other Current Liabilities, Adjustments    
Government Assistance, Liability [Roll Forward]    
Total deduction $ 0  
Other Current Liabilities    
Government Assistance, Liability [Roll Forward]    
Total deduction   $ (9)
Performance-Based Disbursements    
Government Assistance, Liability [Roll Forward]    
Total deduction $ 0 $ (8)
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration] Operating and maintenance Operating and maintenance
Loan forgiveness and other adjustments    
Government Assistance, Liability [Roll Forward]    
Total deduction $ (4) $ (57)
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration] Operating and maintenance Operating and maintenance
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (VIE) (Narrative) (Details)
$ in Millions
Mar. 31, 2026
USD ($)
recoveryBond
Dec. 31, 2025
USD ($)
Aug. 31, 2024
USD ($)
Dec. 31, 2022
USD ($)
Public Utility, Property, Plant and Equipment [Line Items]        
Number of recovery bonds issued | recoveryBond 3      
Receivables Securitization Program - Stated Maturity: 2027 | PG&E AR Facility, LLC (SPV)        
Public Utility, Property, Plant and Equipment [Line Items]        
Accounts receivable, net $ 2,900 $ 3,200    
Receivables Securitization Program - Stated Maturity: 2027 | Utility        
Public Utility, Property, Plant and Equipment [Line Items]        
Long-term debt, gross 1,750 1,800    
Recovery Bonds | Secured Debt        
Public Utility, Property, Plant and Equipment [Line Items]        
Debt instrument, face amount 3,000 3,100 $ 3,260  
SB 901 securitization | Secured Debt        
Public Utility, Property, Plant and Equipment [Line Items]        
Debt instrument, face amount $ 7,100 $ 7,100   $ 7,500
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Wildfire Fund) (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Jul. 12, 2019
Public Utility, Property, Plant and Equipment [Line Items]          
Litigation liability, current $ 193        
Wildfire Fund asset 295   $ 297    
Litigation contribution, net 3,600        
Amortization and accretion 102 $ 76      
Utility          
Public Utility, Property, Plant and Equipment [Line Items]          
Wildfire Fund asset 295   297    
Amortization and accretion 102 $ 76      
Other Current Liabilities          
Public Utility, Property, Plant and Equipment [Line Items]          
Wildfire fund, noncurrent $ 378        
Wildfire Fund Asset          
Public Utility, Property, Plant and Equipment [Line Items]          
Estimated insurance recoveries     134    
Wildfire Recovery Compensation Program          
Public Utility, Property, Plant and Equipment [Line Items]          
Litigation settlement loss     $ 1,100    
Wildfire Fund Asset          
Public Utility, Property, Plant and Equipment [Line Items]          
Finite-lived intangible asset, useful life       20 years 15 years
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Pension Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Service cost for benefits earned $ 115 $ 106
Interest cost 256 252
Expected return on plan assets (307) (263)
Amortization of prior service cost (credit) (1) (1)
Amortization of net actuarial loss (gain) 1 0
Net periodic benefit cost 64 94
Regulatory account transfer 20 (10)
Net periodic benefit cost 84 84
Other Benefits    
Defined Benefit Plan Disclosure [Line Items]    
Service cost for benefits earned 11 9
Interest cost 20 18
Expected return on plan assets (39) (37)
Amortization of prior service cost (credit) 1 1
Amortization of net actuarial loss (gain) (4) (6)
Net periodic benefit cost (11) (15)
Regulatory account transfer 0 0
Net periodic benefit cost $ (11) $ (15)
v3.26.1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance $ 32,792 $ 30,401
Unrealized gain (loss) on investments (6) 7
Net current period other comprehensive gain (loss) (6) 7
Ending balance 33,502 30,937
Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Unrealized gain (loss) on investments 0 0
Amount attributable to tax, before reclassification 0 0
Net current period other comprehensive gain (loss) 0 0
Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Unrealized gain (loss) on investments 0 0
Amount attributable to tax, before reclassification 0 0
Net current period other comprehensive gain (loss) 0 0
Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Unrealized gain (loss) on investments (6) 7
Amount attributable to tax, before reclassification 3 2
Net current period other comprehensive gain (loss) (6) 7
Accumulated Other Comprehensive Income (Loss)    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (20) (14)
Ending balance (26) (7)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (47) (35)
Ending balance (47) (35)
Accumulated Other Comprehensive Income (Loss) | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 19 18
Ending balance 19 18
Accumulated Other Comprehensive Income (Loss) | Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance 8 3
Ending balance 2 10
Amortization of net actuarial loss (gain)    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income (2) (4)
Amortization of net actuarial loss (gain) | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 0 0
Amount attributable to tax, reclassification 0 0
Amortization of net actuarial loss (gain) | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income (2) (4)
Amount attributable to tax, reclassification 1 1
Amortization of net actuarial loss (gain) | Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 0 0
Amount attributable to tax, reclassification 0 0
Regulatory account transfer    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 2 4
Regulatory account transfer | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 0 0
Amount attributable to tax, reclassification 0 0
Regulatory account transfer | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 2 4
Amount attributable to tax, reclassification 1 1
Regulatory account transfer | Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 0 0
Amount attributable to tax, reclassification $ 0 $ 0
v3.26.1
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Jun. 30, 2022
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets $ 15,722 $ 15,981  
Pension benefits      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 381 400  
Environmental compliance costs      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 1,140 1,158  
Price risk management      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 97 100  
Catastrophic event memorandum account      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 466 666  
Wildfire-related accounts      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 1,360 1,626  
Deferred income taxes      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 6,460 6,157  
Financing costs      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 199 202  
SB 901 securitization      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets 5,058 5,089 $ 5,500
Other      
Regulatory Assets [Line Items]      
Total noncurrent regulatory assets $ 561 $ 583  
v3.26.1
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Jun. 30, 2022
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities $ 20,265 $ 20,188  
Cost of removal obligations      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 9,680 9,488  
Public purpose programs      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,203 1,169  
Employee benefit plans      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,049 1,043  
Transmission tower wireless licenses      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 254 257  
SB 901 securitization      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 5,898 6,010 $ 5,540
Wildfire self-insurance      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,041 1,035  
Other      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities $ 1,140 $ 1,186  
v3.26.1
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts $ 1,596 $ 3,119
Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 5,025 6,300
Electric distribution | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 2,796 1,465
Electric transmission | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 9 37
Electric transmission | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 133 122
Gas distribution and transmission | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 92 78
Gas distribution and transmission | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 89 142
Energy procurement | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 75 1,502
Energy procurement | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 1,184 2,711
Public purpose programs | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 492 472
Public purpose programs | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 258 151
Wildfire-related accounts | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 420 338
Wildfire-related accounts | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 71 84
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 60 278
Catastrophic event memorandum account | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 27 181
SFGO sale | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 20 83
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 1 1
Other | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 487 608
Other | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts $ 407 $ 1,166
v3.26.1
DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)
Mar. 31, 2026
Dec. 31, 2025
Utility revolving credit facility    
Debt [Line Items]    
Maximum Facility Limit $ 7,800,000,000  
Loans Outstanding (2,325,000,000)  
Letters of Credit Outstanding (291,000,000)  
Facility Availability 5,184,000,000  
Utility revolving credit facility | PG&E Corporation revolving credit facility    
Debt [Line Items]    
Maximum Facility Limit 650,000,000  
Loans Outstanding 0  
Letters of Credit Outstanding 0  
Facility Availability 650,000,000  
Utility revolving credit facility | Utility    
Debt [Line Items]    
Maximum Facility Limit 5,400,000,000  
Loans Outstanding (575,000,000)  
Letters of Credit Outstanding (291,000,000)  
Facility Availability 4,534,000,000  
Letter of credit sublimit 2,000,000,000.0  
Utility Receivables Securitization Program | Utility    
Debt [Line Items]    
Maximum Facility Limit 1,750,000,000  
Loans Outstanding (1,750,000,000) $ (1,800,000,000)
Letters of Credit Outstanding 0  
Facility Availability $ 0  
v3.26.1
DEBT (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended
Feb. 19, 2026
Mar. 31, 2026
Mar. 31, 2025
Feb. 20, 2026
Dec. 31, 2025
Dec. 04, 2023
First Mortgage Bonds Due 2029 | Utility            
Debt [Line Items]            
Debt instrument, face amount       $ 400    
Interest rate       6.10%    
First Mortgage Bonds Due 2036 | Utility            
Debt [Line Items]            
Debt instrument, face amount       $ 1,000    
Interest rate       5.20%    
First Mortgage Bonds Due 2056 | Utility            
Debt [Line Items]            
Debt instrument, face amount       $ 800    
Interest rate       6.00%    
First Mortgage Bonds Due 2026 | Utility            
Debt [Line Items]            
Debt instrument, face amount       $ 600    
Interest rate       2.95%    
Fixed-to-Fixed Reset Rate Junior Subordinated Notes Due 2056 | PG&E Corporation            
Debt [Line Items]            
Debt instrument, face amount $ 1,000          
Interest rate 6.85%          
Interest rate reset period 5 years          
Basis spread on variable rate 3.225%          
Convertible Notes due 2027 | PG&E Corporation | Secured Debt            
Debt [Line Items]            
Debt instrument, face amount           $ 2,150
Interest rate           4.25%
Debt financial instrument   $ 2,140     $ 2,140  
Debt issuance costs   11     $ 13  
Interest expense   $ 23 $ 23      
v3.26.1
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Jun. 30, 2022
Dec. 31, 2025
Debt [Line Items]        
Regulatory assets $ 15,722     $ 15,981
Regulatory liabilities 20,265     20,188
SB 901 securitization        
Debt [Line Items]        
Regulatory liabilities 5,898   $ 5,540 6,010
SB 901 securitization | Secured Debt        
Debt [Line Items]        
Initial shareholder contribution     2,000  
Additional contributions funded by tax benefits 7,590      
Amortization of regulatory asset and liability 82 $ 74    
Nothern California Wild Fire        
Debt [Line Items]        
Loss contingency, costs incurred     7,500  
SB 901 securitization        
Debt [Line Items]        
Regulatory assets $ 5,058   $ 5,500 $ 5,089
v3.26.1
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Financial Statement Impact) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
SB 901 securitization regulatory asset    
Beginning balance $ 15,981  
Ending balance 15,722  
SB 901 securitization regulatory liability    
Beginning balance (20,188)  
Ending balance (20,265)  
SB 901 Securitization Inception    
SB 901 securitization regulatory liability    
Beginning balance (6,010) $ (6,295)
Amortization 113 93
Additions (1) (1)
Ending balance (5,898) (6,203)
Increase in regulatory liabilities 1 1
SB 901 Securitization Inception | Customer credit trust    
SB 901 securitization regulatory liability    
Additions (1) (1)
Increase in regulatory liabilities 1 1
SB 901 Securitization Inception    
SB 901 securitization regulatory asset    
Beginning balance 5,089 5,194
Amortization (31) (19)
Ending balance $ 5,058 $ 5,175
v3.26.1
EQUITY (Schedule of Dividend Paid or Declared) (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended
Feb. 19, 2026
Dec. 11, 2025
Mar. 31, 2026
Dec. 31, 2025
Mar. 31, 2025
Schedule Of Changes In Equity [Line Items]          
Aggregate amount, common stock     $ 111.0   $ 55.0
Aggregate amount, preferred stock     $ 27.0   27.0
PG&E Corporation          
Schedule Of Changes In Equity [Line Items]          
Amount per Share, common stock (in dollars per share)     $ 0.05 $ 0.05  
Aggregate amount, common stock $ 111.0 $ 110.0      
Aggregate amount, preferred stock     $ 24.0   $ 0.0
Utility          
Schedule Of Changes In Equity [Line Items]          
Aggregate amount, common stock 625.0        
6.000% Series A Mandatory Convertible Preferred Stock, no par value | PG&E Corporation          
Schedule Of Changes In Equity [Line Items]          
Amount per Share, preferred stock (in dollars per share)     $ 0.75 $ 0.75  
Aggregate amount, preferred stock 24.0 24.0      
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Utility          
Schedule Of Changes In Equity [Line Items]          
Aggregate amount, preferred stock $ 3.5 $ 3.5      
v3.26.1
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, $ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Numerator:    
Income Available for Common Shareholders $ 858 $ 607
Mandatory Convertible Preferred Stock dividends 27 27
Income Available for Common Shareholders $ 858 $ 607
Denominator:    
Weighted average common shares outstanding, basic (in shares) 2,199,000,000 2,195,000,000
Weighted average common share outstanding, diluted (in shares) 2,281,000,000 2,200,000,000
Total income per common share:    
Basic (in dollars per share) $ 0.39 $ 0.28
Diluted (in dollars per share) $ 0.39 $ 0.28
PG&E Corporation    
Numerator:    
Income Available for Common Shareholders $ 858 $ 607
Mandatory Convertible Preferred Stock dividends 24 0
Income Available for Common Shareholders $ 882 $ 607
Denominator:    
Weighted average common shares outstanding, basic (in shares) 2,199,000,000 2,195,000,000
Dilutive effect of Employee stock-based compensation (in shares) 4,000,000 5,000,000
Dilutive effect of Mandatory Convertible Preferred Stock (in shares) 78,000,000 0
Weighted average common share outstanding, diluted (in shares) 2,281,000,000 2,200,000,000
Total income per common share:    
Basic (in dollars per share) $ 0.39 $ 0.28
Diluted (in dollars per share) $ 0.39 $ 0.28
Number of shares sold (in shares) 477,743,590 477,743,590
v3.26.1
DERIVATIVES (Narrative) (Details)
Mar. 31, 2026
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]    
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Regulatory assets Regulatory assets
v3.26.1
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)
Mar. 31, 2026
MMBTU
MWh
Dec. 31, 2025
MWh
MMBTU
Natural Gas | Forwards, futures, and swaps    
Derivative [Line Items]    
Contract Volume 204,557,995 232,825,834
Natural Gas | Options    
Derivative [Line Items]    
Contract Volume 34,175,000 48,215,000
Electricity (MWh) | Forwards, futures, and swaps    
Derivative [Line Items]    
Contract Volume | MWh 6,903,828 7,196,942
Electricity (MWh) | Options    
Derivative [Line Items]    
Contract Volume 2,678,000 1,650,800
Electricity (MWh) | Congestion Revenue Rights    
Derivative [Line Items]    
Contract Volume | MWh 83,584,734 93,712,644
v3.26.1
DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Contract - Utility - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets $ 106 $ 60
Netting, Assets 0 0
Cash Collateral 30 0
Total Derivative Balance, Assets 136 60
Current assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets 152 165
Netting, Assets (28) (46)
Cash Collateral 19 0
Total Derivative Balance, Assets 143 119
Noncurrent assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets 156 170
Netting, Assets (2) (6)
Cash Collateral 0 0
Total Derivative Balance, Assets 154 164
Current liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Liabilities (103) (169)
Netting, Liabilities 28 46
Cash Collateral 11 0
Total Derivative Balance, Liabilities (64) (123)
Noncurrent liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Liabilities (99) (106)
Netting, Liabilities 2 6
Cash Collateral 0 0
Total Derivative Balance, Liabilities $ (97) $ (100)
v3.26.1
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Assets:    
Price risk management instruments, netting $ (11) $ (52)
TOTAL ASSETS 8,536 8,274
Liabilities:    
Price risk management instruments, netting (41) (52)
TOTAL LIABILITIES 161 223
Amount primarily related to deferred taxes on appreciation of investment value 854 881
Self-insurance investments    
Assets:    
TOTAL ASSETS 1,000 1,000
Pacific Casualty Insurance Company, LLC    
Assets:    
TOTAL ASSETS 119 77
Short-term investments    
Assets:    
Short-term investments 1,016 634
Self-insurance investments    
Assets:    
Short-term investments 1,178 1,120
TOTAL ASSETS 1,178 1,120
Nuclear decommissioning trusts    
Assets:    
Short-term investments 53 94
Global equity securities 2,336 2,433
Fixed-income securities 2,625 2,558
Price risk management instruments, netting   0
TOTAL ASSETS 5,039 5,111
Customer credit trust    
Assets:    
Short-term investments 127 111
Global equity securities 0 0
Fixed-income securities 564 693
TOTAL ASSETS 691 804
Rabbi trusts    
Assets:    
Short-term investments 117 115
Global equity securities 5 5
Life insurance contracts 65 65
TOTAL ASSETS 187 185
Long-term disability trust    
Assets:    
Short-term investments 1 10
TOTAL ASSETS 128 137
Total price risk management instruments    
Assets:    
Price risk management instruments, netting (11) (52)
Price risk management instruments, assets 297 283
Electricity    
Assets:    
Price risk management instruments, netting (9) (6)
Price risk management instruments, assets 282 296
Liabilities:    
Price risk management instruments, netting (39) (6)
Price risk management instruments, liabilities 160 204
Gas    
Assets:    
Price risk management instruments, netting (2) (46)
Price risk management instruments, assets 15 (13)
Liabilities:    
Price risk management instruments, netting (2) (46)
Price risk management instruments, liabilities 1 19
Level 1    
Assets:    
TOTAL ASSETS 6,529 6,334
Liabilities:    
TOTAL LIABILITIES 0 0
Level 1 | Short-term investments    
Assets:    
Short-term investments 1,016 634
Level 1 | Self-insurance investments    
Assets:    
Short-term investments 1,178 1,120
TOTAL ASSETS 1,178 1,120
Level 1 | Nuclear decommissioning trusts    
Assets:    
Short-term investments 53 94
Global equity securities 2,336 2,433
Fixed-income securities 1,518 1,445
TOTAL ASSETS 3,907 3,972
Level 1 | Customer credit trust    
Assets:    
Short-term investments 127 111
Global equity securities 0
Fixed-income securities 178 367
TOTAL ASSETS 305 478
Level 1 | Rabbi trusts    
Assets:    
Short-term investments 117 115
Global equity securities 5 5
Life insurance contracts 0 0
TOTAL ASSETS 122 120
Level 1 | Long-term disability trust    
Assets:    
Short-term investments 1 10
TOTAL ASSETS 1 10
Level 1 | Total price risk management instruments    
Assets:    
Price risk management instruments, gross subject to netting 0 0
Level 1 | Electricity    
Assets:    
Price risk management instruments, gross subject to netting 0 0
Liabilities:    
Price risk management instruments, gross subject to netting 0 0
Level 1 | Gas    
Assets:    
Price risk management instruments, gross subject to netting 0 0
Liabilities:    
Price risk management instruments, gross subject to netting 0 0
Level 2    
Assets:    
TOTAL ASSETS 1,606 1,556
Liabilities:    
TOTAL LIABILITIES 34 145
Level 2 | Short-term investments    
Assets:    
Short-term investments 0 0
Level 2 | Self-insurance investments    
Assets:    
Short-term investments 0 0
TOTAL ASSETS 0 0
Level 2 | Nuclear decommissioning trusts    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Fixed-income securities 1,107 1,113
TOTAL ASSETS 1,107 1,113
Level 2 | Customer credit trust    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Fixed-income securities 386 326
TOTAL ASSETS 386 326
Level 2 | Rabbi trusts    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Life insurance contracts 65 65
TOTAL ASSETS 65 65
Level 2 | Long-term disability trust    
Assets:    
Short-term investments 0 0
TOTAL ASSETS 0 0
Level 2 | Total price risk management instruments    
Assets:    
Price risk management instruments, gross subject to netting 48 52
Level 2 | Electricity    
Assets:    
Price risk management instruments, gross subject to netting 31 19
Liabilities:    
Price risk management instruments, gross subject to netting 31 80
Level 2 | Gas    
Assets:    
Price risk management instruments, gross subject to netting 17 33
Liabilities:    
Price risk management instruments, gross subject to netting 3 65
Level 3    
Assets:    
TOTAL ASSETS 260 283
Liabilities:    
TOTAL LIABILITIES 168 130
Level 3 | Short-term investments    
Assets:    
Short-term investments 0 0
Level 3 | Self-insurance investments    
Assets:    
Short-term investments 0 0
TOTAL ASSETS 0 0
Level 3 | Nuclear decommissioning trusts    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Fixed-income securities 0 0
TOTAL ASSETS 0 0
Level 3 | Customer credit trust    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Fixed-income securities 0 0
TOTAL ASSETS 0 0
Level 3 | Rabbi trusts    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Life insurance contracts 0 0
TOTAL ASSETS 0 0
Level 3 | Long-term disability trust    
Assets:    
Short-term investments 0 0
TOTAL ASSETS 0 0
Level 3 | Total price risk management instruments    
Assets:    
Price risk management instruments, gross subject to netting 260 283
Level 3 | Electricity    
Assets:    
Price risk management instruments, gross subject to netting 260 283
Liabilities:    
Price risk management instruments, gross subject to netting 168 130
Level 3 | Gas    
Assets:    
Price risk management instruments, gross subject to netting 0 0
Liabilities:    
Price risk management instruments, gross subject to netting 0 0
Assets measured at NAV | Nuclear decommissioning trusts    
Assets:    
Assets measured at NAV 25 26
Assets measured at NAV | Long-term disability trust    
Assets:    
Assets measured at NAV $ 127 $ 127
v3.26.1
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details)
$ in Millions
Mar. 31, 2026
USD ($)
$ / shares
Dec. 31, 2025
USD ($)
$ / shares
Market approach | Congestion revenue rights    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ $ 229 $ 252
Liabilities | $ 75 83
Discounted cash flow | Power purchase agreements    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ 31 31
Liabilities | $ $ 93 $ 47
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) (79) (74)
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) 74 74
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) 2 2
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) 10 11
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) 102 106
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) 51 53
v3.26.1
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Asset balance, beginning of period $ 153 $ 127
Included in regulatory assets and liabilities or balancing accounts (61) (1)
Asset balance, end of period $ 92 $ 126
v3.26.1
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Carrying Amount    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument $ 6,326 $ 5,360
Carrying Amount | Convertible Notes due 2027 | Secured Debt    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 2,100  
Carrying Amount | Utility    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 41,887 38,145
Level 2 | Fair Value    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 6,715 5,697
Level 2 | Fair Value | Convertible Notes due 2027 | Secured Debt    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 2,200  
Level 2 | Fair Value | Utility    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument $ 38,779 $ 35,565
v3.26.1
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Debt Securities, Available-for-sale [Line Items]    
Amount primarily related to deferred taxes on appreciation of investment value $ 854 $ 881
Nuclear decommissioning trusts    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 3,023 2,975
Total Unrealized Gains 2,075 2,188
Total Unrealized Losses (59) (52)
Total Fair Value 5,039 5,111
Nuclear decommissioning trusts | Short-term investments    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 53 94
Total Unrealized Gains 0 0
Total Unrealized Losses 0 0
Total Fair Value 53 94
Nuclear decommissioning trusts | Global equity securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 323 324
Total Unrealized Gains 2,045 2,140
Total Unrealized Losses (7) (5)
Total Fair Value 2,361 2,459
Nuclear decommissioning trusts | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 2,647 2,557
Total Unrealized Gains 30 48
Total Unrealized Losses (52) (47)
Total Fair Value 2,625 2,558
Customer credit trust    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 693 800
Total Unrealized Gains 1 5
Total Unrealized Losses (3) (1)
Total Fair Value 691 804
Customer credit trust | Short-term investments    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 127 111
Total Unrealized Gains 0 0
Total Unrealized Losses 0 0
Total Fair Value 127 111
Customer credit trust | Global equity securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 0 0
Total Unrealized Gains 0 0
Total Unrealized Losses 0 0
Total Fair Value 0 0
Customer credit trust | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 566 689
Total Unrealized Gains 1 5
Total Unrealized Losses (3) (1)
Total Fair Value $ 564 $ 693
v3.26.1
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Nuclear decommissioning trusts    
Debt Securities, Available-for-sale [Line Items]    
Total maturities of fixed-income securities $ 5,039 $ 5,111
Nuclear decommissioning trusts | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Less than 1 year 58  
1–5 years 904  
5–10 years 592  
More than 10 years 1,071  
Total maturities of fixed-income securities 2,625 2,558
Customer credit trust    
Debt Securities, Available-for-sale [Line Items]    
Total maturities of fixed-income securities 691 804
Customer credit trust | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Less than 1 year 22  
1–5 years 354  
5–10 years 51  
More than 10 years 137  
Total maturities of fixed-income securities $ 564 $ 693
v3.26.1
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2026
Mar. 31, 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Proceeds from sales and maturities of nuclear decommissioning trust investments $ 400 $ 278
Nuclear decommissioning trusts    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Proceeds from sales and maturities of nuclear decommissioning trust investments 400 278
Gross realized gains on securities 21 2
Gross realized losses on securities (8) (6)
Customer credit trust    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Proceeds from sales and maturities of nuclear decommissioning trust investments 116 99
Gross realized gains on securities 5 3
Gross realized losses on securities $ (3) $ (3)
v3.26.1
WILDFIRE-RELATED CONTINGENCIES - Litigation Payments (Details)
$ in Millions
Mar. 31, 2026
USD ($)
Loss Contingencies [Line Items]  
Litigation payment $ 3,496
2019 Kincade Fire  
Loss Contingencies [Line Items]  
Litigation payment 1,318
2021 Dixie fire  
Loss Contingencies [Line Items]  
Litigation payment 2,009
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Litigation payment $ 169
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2021 Dixie Fire and 2022 Mosquito Fire) (Details)
$ in Millions
 3 Months Ended
Jul. 13, 2021
USD ($)
a
injury
structure
Mar. 31, 2026
USD ($)
Apr. 15, 2026
complaint
claimHolder
plaintiff
Jan. 31, 2026
entity
Dec. 31, 2025
USD ($)
Sep. 06, 2022
a
fatality
structure
injury
Oct. 23, 2019
a
structure
fatality
injury
2019 Kincade Fire              
Loss Contingencies [Line Items]              
Number of acres burned (acre) | a             77,758
Number of fatalities (fatality) | fatality             0
Number of injuries | injury             4
Number of structures destroyed (structure) | structure             374
Number of structures damaged (structure) | structure             60
Loss contingency liability         $ 1,325    
Insurance receivable fully collected   $ 430          
Liability insurance coverage, insurance receivable. fully recoveries   115          
2021 Dixie fire              
Loss Contingencies [Line Items]              
Number of acres burned (acre) | a 963,309            
Number of structures destroyed (structure) | structure 1,311            
Number of structures damaged (structure) | structure 94            
Number of residential structures destroyed (structure) | structure 763            
Number of multi-family residential structures destroyed (structure) | structure 12            
Number of commercial residential structures destroyed (structure) | structure 8            
Number of commercial non-residential structures destroyed (structure) | structure 148            
Number of detached structures destroyed (structure) | structure 466            
Number of first responder injuries (injury) | injury 4            
Estimated losses         2,150    
Loss contingency, costs incurred $ 650            
Insurance receivable   521          
Probable of recovery   2,307          
2021 Dixie fire | Wildfire Fund              
Loss Contingencies [Line Items]              
Probable of recovery   1,150          
Probable of recovery received   892          
2021 Dixie fire | FERC TO rates              
Loss Contingencies [Line Items]              
Probable of recovery   97          
2021 Dixie fire | WEMA              
Loss Contingencies [Line Items]              
Probable of recovery   539          
2021 Dixie fire | National Park              
Loss Contingencies [Line Items]              
Number of acres burned (acre) | a 70,000            
2021 Dixie fire | National Forrest              
Loss Contingencies [Line Items]              
Number of acres burned (acre) | a 685,000            
2021 Dixie fire | Subsequent Event              
Loss Contingencies [Line Items]              
Number of complaints (complaint) | claimHolder     190        
Number of plaintiffs represented by complaints | claimHolder     9,062        
2022 Mosquito fire              
Loss Contingencies [Line Items]              
Number of acres burned (acre) | a           76,788  
Number of fatalities (fatality) | fatality           0  
Number of injuries | injury           0  
Number of structures destroyed (structure) | structure           78  
Number of structures damaged (structure) | structure           13  
Loss contingency liability   400     $ 350    
Number of residential structures destroyed (structure) | structure           44  
Number of detached structures destroyed (structure) | structure           40  
Insurance receivable   416          
Probable of recovery   477          
Percentage of fire contained           100.00%  
Number of public entities | entity       5      
Loss contingency accrual, period increase (decrease)   50          
2022 Mosquito fire | Wildfire Fund              
Loss Contingencies [Line Items]              
Probable of recovery   0          
2022 Mosquito fire | FERC TO rates              
Loss Contingencies [Line Items]              
Probable of recovery   7          
2022 Mosquito fire | WEMA              
Loss Contingencies [Line Items]              
Probable of recovery   $ 54          
2022 Mosquito fire | Subsequent Event              
Loss Contingencies [Line Items]              
Number of complaints (complaint) | complaint     30        
Number of plaintiffs represented by complaints | plaintiff     2,931        
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
2019 Kincade Fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance $ 38
Accrued Losses 0
Payments (31)
Loss accrual, ending balance 7
2021 Dixie fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance 243
Accrued Losses 0
Payments (101)
Loss accrual, ending balance 142
2022 Mosquito fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance 243
Accrued Losses 50
Payments (62)
Loss accrual, ending balance $ 231
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery $ 2,307
Probable of recovery, legal costs 152
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 477
Probable of recovery, legal costs 76
Insurance | 2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery 521
Insurance | 2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 416
FERC TO rates | 2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery 97
FERC TO rates | 2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 7
WEMA | 2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery 539
WEMA | 2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 54
Wildfire Fund | 2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery 1,150
Wildfire Fund | 2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery $ 0
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Self-Insurance) (Details) - CPUC
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
Loss Contingencies [Line Items]  
Self insurance amount $ 1,000
Self insurance deductible, percent 0.05
Self insurance deductible maximum $ 50
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
Insurance Receivable [Roll Forward]  
Insurance receivable, beginning balance $ 282
Accrued insurance recoveries 53
Reimbursements (73)
Insurance receivable, ending balance 262
2021 Dixie fire  
Loss Contingencies [Line Items]  
Insurance receivable 521
Insurance Receivable [Roll Forward]  
Insurance receivable, beginning balance 1
Accrued insurance recoveries 0
Reimbursements 0
Insurance receivable, ending balance 1
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Insurance receivable 416
Insurance Receivable [Roll Forward]  
Insurance receivable, beginning balance 281
Accrued insurance recoveries 53
Reimbursements (73)
Insurance receivable, ending balance $ 261
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery $ 2,307
2021 Dixie fire | FERC TO rates  
Loss Contingencies [Line Items]  
Probable of recovery 97
2021 Dixie fire | WEMA  
Loss Contingencies [Line Items]  
Probable of recovery 539
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 477
2022 Mosquito fire | FERC TO rates  
Loss Contingencies [Line Items]  
Probable of recovery 7
2022 Mosquito fire | WEMA  
Loss Contingencies [Line Items]  
Probable of recovery $ 54
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($)
$ in Millions
 3 Months Ended
Aug. 23, 2019
Mar. 31, 2026
Dec. 31, 2025
Loss Contingencies [Line Items]      
Disallowance cap, transmission and distribution equity rate base   $ 5,100  
Initial safety certification, documentation provided, period 90 days    
Initial safety certification, period 12 months    
Expected capitalization, proceeds of bond   $ 21,000  
Extension period   15 years  
Expected capitalization, initial contribution   $ 7,500  
Expected capitalization, annual contribution   $ 300  
Annual contribution period   10 years  
Loss contingency, expected capitalization, continuation account   $ 18,000  
Loss contingency, expected capitalization, non-bypassable charge from customers   9,000  
Loss contingency, expected capitalization, contributed by the utilities   5,100  
Loss contingency, expected capitalization, additional contributed by the utilities   $ 3,900  
Loss contingency, estimate for life   20 years  
Insurance receivable   $ 262 $ 282
2021 Dixie fire      
Loss Contingencies [Line Items]      
Insurance receivable   1 $ 1
2021 Dixie fire | Noncurrent assets – other      
Loss Contingencies [Line Items]      
Insurance receivable   251  
2021 Dixie fire | Noncurrent assets – other | Utility      
Loss Contingencies [Line Items]      
Insurance receivable   $ 7  
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Changes in Accrued Wildfire Fund Recoveries) (Details) - 2021 Dixie fire
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
Loss Contingency Accrual [Roll Forward]  
Wildfire fund receivable, beginning balance $ 299
Accrued Wildfire Fund recoveries 0
Claims paid by Wildfire Fund (41)
Wildfire fund receivable, ending balance $ 258
v3.26.1
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Securities Litigation and Claims in District Court) (Details) - Wildfire-Related Class Action
$ in Millions
Jan. 10, 2026
USD ($)
Mar. 31, 2026
USD ($)
Feb. 22, 2019
notice
Jun. 30, 2018
lawsuit
Loss Contingencies [Line Items]        
Loss contingency liability   $ 300    
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit       2
Number of public offerings of notes with complaints against underwriters (offering) | notice     4  
Loss contingency, damages sought $ 100      
Percentage of common stock owned, Fire Victim Trust if common issues additional shares   22.19%    
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Interim Rate Relief Subject to Refund) (Details) - Utility - USD ($)
$ in Millions
Mar. 07, 2024
Jun. 15, 2023
Wildfire and Gas Safety Costs Interim Rate Relief    
Loss Contingencies [Line Items]    
Cost recovery   $ 2,500
Interim revenue requirement   688
Interim rate relief $ 516  
Remaining value recoverable $ 172  
Wildfire Costs Interim Rate Relief    
Loss Contingencies [Line Items]    
Recorded expenditures, expenses   726
Recorded expenditures, capital expenditures   1,500
Gas Safety Costs Interim Rate Relief    
Loss Contingencies [Line Items]    
Recorded expenditures, expenses   120
Recorded expenditures, capital expenditures   $ 118
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Mar. 31, 2025
Commitments and Contingencies Disclosure [Abstract]    
Accrued legal liabilities $ 145 $ 78
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Tax Matters) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2026
Dec. 31, 2024
Investments, Owned, Federal Income Tax Note [Line Items]    
Income tax deduction, repair costs $ 850  
Income tax deduction, customer bill credits $ 400  
Utility    
Investments, Owned, Federal Income Tax Note [Line Items]    
Income tax deduction, accrued amount   $ 70
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]    
Topock natural gas compressor station $ 301 $ 315
Hinkley natural gas compressor station 96 99
Former MGP sites owned by the Utility or third parties 867 715
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 75 71
Fossil fuel-fired generation facilities and sites 17 17
Total environmental remediation liability $ 1,356 $ 1,217
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details)
$ in Billions
Mar. 31, 2026
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
Amount of environmental loss accrual expected to be recovered $ 1.1
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Contingencies) (Details) - USD ($)
$ in Millions
Mar. 31, 2026
Dec. 31, 2025
Site Contingency [Line Items]    
Topock natural gas compressor station $ 301 $ 315
Hinkley natural gas compressor station 96 99
Former MGP sites owned by the Utility or third parties 867 715
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 75 71
Fossil fuel-fired generation facilities and sites $ 17 $ 17
Utility    
Site Contingency [Line Items]    
Remediation cost recovery percentage 90.00%  
Maximum    
Site Contingency [Line Items]    
Topock natural gas compressor station $ 498  
Hinkley natural gas compressor station 218  
Former MGP sites owned by the Utility or third parties 1,400  
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 151  
Fossil fuel-fired generation facilities and sites $ 30  
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Purchase Commitments) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2026
USD ($)
nuclearGeneratingUnit
Long-term Purchase Commitment [Line Items]  
Number of nuclear generating units (nuclear generating unit) | nuclearGeneratingUnit 2
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance  
Long-term Purchase Commitment [Line Items]  
Insurance coverage, loss $ 400
Humboldt Bay Unit  
Long-term Purchase Commitment [Line Items]  
Amount of property damage coverage provided by NEIL 50
Nuclear Incident  
Long-term Purchase Commitment [Line Items]  
Amount of property damage and business interruption coverage 3,200
Non-Nuclear Incident  
Long-term Purchase Commitment [Line Items]  
Amount of property damage and business interruption coverage 2,500
European Mutual Association for Nuclear Insurance  
Long-term Purchase Commitment [Line Items]  
Full insurance policy limit 200
Nuclear Electric Insurance Limited  
Long-term Purchase Commitment [Line Items]  
Potential premium obligation $ 44
v3.26.1
OTHER CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details)
$ in Billions
Dec. 31, 2025
USD ($)
Utility  
Long-term Purchase Commitment [Line Items]  
Total purchase commitments $ 33