PG&E CORP, 10-K filed on 2/12/2026
Annual Report
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Audit Information [Abstract]  
Auditor Firm ID 34
Auditor Name DELOITTE & TOUCHE LLP
Auditor Location San Francisco, California
v3.25.4
Cover Page - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Feb. 04, 2026
Jun. 30, 2025
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 1-12609    
Entity Incorporation, State or Country Code CA    
Entity Tax Identification Number 94-3234914    
Entity Address, Address Line One 300 Lakeside Drive    
Entity Address, City or Town Oakland,    
Entity Address, State or Province CA    
Entity Address, Postal Zip Code 94612    
City Area Code 415    
Local Phone Number 973-1000    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Bankruptcy Proceedings, Reporting Current true    
Entity Public Float     $ 37,246
Entity Common Stock, Shares Outstanding (in shares)   2,675,711,544  
Documents Incorporated by Reference
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the Joint Proxy Statement relating to the 2026 Annual Meetings of Shareholders
Part III (Items 10, 11, 12, 13 and 14)
    
Amendment Flag false    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
Entity Registrant Name PG&E CORP    
Entity Central Index Key 0001004980    
Utility      
Document Type 10-K    
Entity File Number 1-2348    
Entity Incorporation, State or Country Code CA    
Entity Tax Identification Number 94-0742640    
Entity Address, Address Line One 300 Lakeside Drive    
Entity Address, City or Town Oakland,    
Entity Address, State or Province CA    
Entity Address, Postal Zip Code 94612    
City Area Code 415    
Local Phone Number 973-7000    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Bankruptcy Proceedings, Reporting Current true    
Entity Common Stock, Shares Outstanding (in shares)   264,374,809  
Documents Incorporated by Reference
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the Joint Proxy Statement relating to the 2026 Annual Meetings of Shareholders
Part III (Items 10, 11, 12, 13 and 14)
    
Entity Registrant Name PACIFIC GAS & ELECTRIC CO    
Entity Central Index Key 0000075488    
The New York Stock Exchange | Common stock, no par value      
Title of 12(b) Security Common stock, no par value    
Trading Symbol PCG    
Security Exchange Name NYSE    
The New York Stock Exchange | 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 $25 per share, 4.36% series A redeemable    
Trading Symbol PCG-PI    
Security Exchange Name NYSEAMER    
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating Revenues      
Total operating revenues $ 24,935 $ 24,419 $ 24,428
Operating Expenses      
Operating and maintenance 11,349 11,808 11,924
SB 901 securitization charges, net 35 33 1,267
Wildfire-related claims, net of recoveries 100 94 64
Wildfire Fund expense 352 383 567
Depreciation, amortization, and decommissioning 4,634 4,189 3,738
Total operating expenses 20,186 19,960 21,757
Operating Income 4,749 4,459 2,671
Interest income 520 604 606
Interest expense (3,028) (3,051) (2,850)
Other income, net 182 300 272
Income Before Income Taxes 2,423 2,312 699
Income tax benefit (280) (200) (1,557)
Net Income 2,703 2,512 2,256
Preferred stock dividend requirement 110 37 14
Income Available for Common Shareholders 2,593 2,475 2,242
Income Available for Common Shareholders $ 2,593 $ 2,475 $ 2,242
Weighted Average Common Shares Outstanding, Basic (in shares) 2,197 2,141 2,064
Weighted Average Common Shares Outstanding, Diluted 2,202 2,147 2,138
Net Income Per Common Share, Basic (in dollars per share) $ 1.18 $ 1.16 $ 1.09
Net Income Per Common Share, Diluted (in dollars per share) $ 1.18 $ 1.15 $ 1.05
Electric      
Operating Revenues      
Total operating revenues $ 18,318 $ 17,811 $ 17,424
Operating Expenses      
Cost of electricity and natural gas 2,609 2,261 2,443
Natural gas      
Operating Revenues      
Total operating revenues 6,617 6,608 7,004
Operating Expenses      
Cost of electricity and natural gas $ 1,107 $ 1,192 $ 1,754
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Net income $ 2,703 $ 2,512 $ 2,256
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively) (11) (7) (16)
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $3, respectively) 5 1 8
Total other comprehensive income (loss) (6) (6) (8)
Comprehensive Income 2,697 2,506 2,248
Preferred stock dividend requirement 110 37 14
Comprehensive Income Attributable to Common Shareholders $ 2,587 $ 2,469 $ 2,234
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Pension and other postretirement benefit plans obligations, tax $ 4 $ 3 $ 6
Net unrealized gain (losses) on available for sale securities, tax $ 2 $ 0 $ 3
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Current Assets    
Cash and cash equivalents $ 713 $ 940
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates) 259 273
Accounts receivable    
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates) 2,267 2,220
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,463 1,487
Regulatory balancing accounts 6,300 7,227
Other (net of allowance for doubtful accounts of $69 million and $35 million at respective dates) 1,719 1,810
Regulatory assets 305 234
Inventories    
Gas stored underground and fuel oil 75 52
Materials and supplies 745 768
Wildfire Fund asset 297 301
Wildfire self-insurance asset 1,043 905
Other 644 999
Total current assets 15,830 17,216
Property, Plant, and Equipment    
Property, Plant, and Equipment 128,989 118,262
Construction work in progress 4,627 4,458
Financing lease ROU asset and other 2 814
Total property, plant, and equipment 133,618 123,534
Accumulated depreciation (37,270) (35,305)
Net property, plant, and equipment 96,348 88,229
Other Noncurrent Assets    
Regulatory assets 15,981 15,561
Customer credit trust 804 377
Nuclear decommissioning trusts 4,230 3,833
Operating lease ROU asset 450 524
Wildfire Fund asset 3,728 4,070
Other (includes noncurrent accounts receivable of $67 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $18 at respective dates) 4,240 3,850
Total other noncurrent assets 29,433 28,215
TOTAL ASSETS 141,611 133,660
Current Liabilities    
Short-term borrowings 2,675 1,523
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates) 821 2,146
Accounts payable    
Trade creditors 3,353 2,748
Regulatory balancing accounts 3,119 3,169
Other 929 748
Operating lease liabilities 90 85
Financing lease liabilities 0 577
Interest payable (includes $72 million and $91 million related to VIEs at respective dates) 764 760
Wildfire-related claims 524 916
Other 4,025 3,658
Total current liabilities 16,300 16,330
Noncurrent Liabilities    
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) 57,387 53,569
Regulatory liabilities 20,188 19,417
Pension and other postretirement benefits 549 808
Asset retirement obligations 5,439 5,444
Deferred income taxes 4,135 3,082
Operating lease liabilities 360 439
Financing lease liabilities 2 4
Other 4,459 4,166
Total noncurrent liabilities 92,519 86,929
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; 2,197,942,874 and 2,193,573,536 shares outstanding at respective dates 31,636 31,555
Reinvested earnings (650) (2,966)
Accumulated other comprehensive loss (25) (19)
Total shareholders’ equity 32,540 30,149
Noncontrolling Interest - Preferred Stock of Subsidiary 252 252
Total equity 32,792 30,401
TOTAL LIABILITIES AND EQUITY $ 141,611 $ 133,660
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Restricted cash and cash equivalents $ 259 $ 273 $ 297
Allowance for doubtful accounts 408 418  
Accounts receivable, after allowance for credit loss, current 2,267 2,220  
Accrued unbilled revenue 1,463 1,487  
Other (net of allowance for doubtful accounts) 69 35  
Long-term debt, classified as current 821 2,146  
Interest payable 764 760  
Long-term debt $ 57,387 $ 53,569  
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) 2,197,942,874 2,193,573,536  
Variable Interest Entity, Primary Beneficiary      
Restricted cash and cash equivalents $ 225 $ 263  
Allowance for doubtful accounts 408 418  
Accounts receivable, after allowance for credit loss, current 1,900 1,900  
Accrued unbilled revenue 1,300 1,300  
Noncurrent accounts receivable 67 82  
Allowance for doubtful accounts, noncurrent 15 18  
Long-term debt, classified as current 221 222  
Interest payable 72 91  
Long-term debt $ 11,700 $ 10,100  
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Flows from Operating Activities      
Net income $ 2,703 $ 2,512 $ 2,256
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, amortization, and decommissioning 4,634 4,189 3,738
Bad debt expense 402 341 636
Allowance for equity funds used during construction (219) (184) (179)
Deferred income taxes and tax credits, net 1,058 1,098 (765)
Wildfire Fund expense 352 383 568
Other (75) 310 (116)
Effect of changes in operating assets and liabilities:      
Accounts receivable (61) (1,061) (369)
Wildfire-related insurance receivable (167) 318 358
Inventories 0 45 (28)
Accounts payable 176 30 (90)
Wildfire-related claims (392) (506) (489)
Other current assets and liabilities 563 (231) 397
Regulatory assets, liabilities, and balancing accounts, net 173 1,545 (429)
Contributions to Wildfire Fund (193) (193) (193)
Other noncurrent assets and liabilities (238) (561) (548)
Net cash provided by operating activities 8,716 8,035 4,747
Cash Flows from Investing Activities      
Capital expenditures (11,787) (10,369) (9,714)
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952 1,980 2,235
Purchases of nuclear decommissioning trust investments (1,993) (2,002) (2,252)
Proceeds from sales and maturities of customer credit trust investments 435 398 556
Purchases of customer credit investments (742) (519) 0
Proceeds from self-insurance investments 1,181 0 0
Purchases of self-insurance investments (1,384) (898) 0
Other 22 35 13
Net cash used in investing activities (12,316) (11,375) (9,162)
Cash Flows from Financing Activities      
Borrowings under credit facilities 4,790 6,873 10,675
Repayments under credit facilities (1,465) (10,122) (10,540)
Borrowings under term loan 575 0 2,100
Repayments under term loan 0 (2,600) (2,181)
Short-term debt financing, net of issuance costs of $0, $1, and $0 at respective dates 0 999 0
Short-term debt matured (1,000) 0 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $38, $5, and $67 at respective dates 4,962 4,495 5,483
Repayments of long-term debt (3,876) (800) (3,075)
Proceeds from issuance of AB 1054 recovery bonds, net of financing fees of $0, $10 and $0 at respective dates 0 1,409 0
Proceeds from DWR loan 0 980 0
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $0, and $27 at respective dates 0 0 2,123
Common stock issued 0 1,128 0
Preferred stock dividends paid (97) 0 0
Other (87) (59) (17)
Net cash provided by financing activities 3,359 3,621 4,400
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents (241) 281 (15)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 1,213 932 947
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 972 1,213 932
Less: Restricted cash and restricted cash equivalents (259) (273) (297)
Cash and cash equivalents at December 31 713 940 635
Supplemental disclosures of cash flow information      
Interest, net of amounts capitalized (2,665) (2,421) (2,286)
Supplemental disclosures of noncash investing and financing activities      
Capital expenditures financed through accounts payable 1,859 1,144 1,105
Operating lease liabilities arising from obtaining ROU assets 0 6 269
Financing lease liabilities arising from obtaining ROU assets 0 43 52
Reclassification of operating lease liabilities to financing lease liabilities 0 0 913
DWR loan forgiveness and performance-based disbursements 148 192 214
Changes to PG&E Corporation common stock and treasury stock in connection with the share exchange with the Fire Victim Trust 0 0 (2,517)
Capital expenditures financed through current assets and non-current liabilities 592 0 0
Common Stock      
Cash Flows from Financing Activities      
Mandatory convertible preferred stock dividends paid (220) (86) 0
Supplemental disclosures of noncash investing and financing activities      
Dividends declared but not yet paid 111 55 21
Mandatory convertible preferred stock      
Cash Flows from Financing Activities      
Mandatory convertible preferred stock issued 0 1,579 0
Supplemental disclosures of noncash investing and financing activities      
Dividends declared but not yet paid 23 23 0
AB 1054 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds (88) (46) (38)
SB 901 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds $ (135) $ (129) $ (130)
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Issuance costs for short-term debt $ 0 $ 1 $ 0
Premium, discount, and issuance costs on proceeds from long-term debt 38 5 67
AB 1054 Recovery Bonds      
Financing fees 0 10 0
Convertible Notes due 2027      
Premium, discount, and issuance costs on proceeds from long-term debt $ 0 $ 0 $ 27
v3.25.4
CONSOLIDATED STATEMENTS OF EQUITY - USD ($)
$ in Millions
Total
Total Shareholders' Equity
Preferred Stock
Common Stock
Treasury Stock
Reinvested Earnings
Accumulated Other Comprehensive Income (Loss)
Non- controlling Interest - Preferred Stock  of Subsidiary
Beginning balance at Dec. 31, 2022 $ 23,075 $ 22,823 $ 0 $ 32,887 $ (2,517) $ (7,542) $ (5) $ 252
Beginning balance (in shares) at Dec. 31, 2022       1,987,784,948        
Beginning balance, treasury (in shares) at Dec. 31, 2022         247,743,590,000,000      
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income 2,256 2,256       2,256    
Other comprehensive loss (8) (8)         (8)  
Common stock issued, net (in shares)       145,812,810        
Common stock issued, net (2,517) (2,517)   $ (2,517)        
Treasury stock disposition (in shares)         (247,743,590,000,000)      
Treasury stock disposition 2,517 2,517     $ 2,517      
Stock-based compensation amortization 4 4   4        
Common stock dividends declared (21) (21)       (21)    
Preferred stock dividend requirement of subsidiary (14) (14)       (14)    
Ending balance at Dec. 31, 2023 25,292 25,040 0 $ 30,374 $ 0 (5,321) (13) 252
Ending balance (in shares) at Dec. 31, 2023       2,133,597,758        
Ending balance, treasury (in shares) at Dec. 31, 2023         0      
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income 2,512 2,512       2,512    
Other comprehensive loss (6) (6)         (6)  
Preferred Stock issued, net 1,579 1,579 1,579          
Common stock issued, net (in shares)       59,975,778        
Common stock issued, net 1,128 1,128   $ 1,128        
Stock-based compensation amortization 53 53   53        
Common stock dividends declared (120) (120)       (120)    
Preferred stock dividend requirement of subsidiary (37) (37)       (37)    
Ending balance at Dec. 31, 2024 $ 30,401 30,149 1,579 $ 31,555 $ 0 (2,966) (19) 252
Ending balance (in shares) at Dec. 31, 2024 2,193,573,536     2,193,573,536        
Ending balance, treasury (in shares) at Dec. 31, 2024         0      
Increase (Decrease) in Stockholders' Equity [Roll Forward]                
Net income $ 2,703 2,703       2,703    
Other comprehensive loss (6) (6)         (6)  
Common stock issued, net (in shares)       4,369,338        
Common stock issued, net (1) (1)   $ (1)        
Stock-based compensation amortization 82 82   82        
Common stock dividends declared (277) (277)       (277)    
Preferred stock dividend requirement of subsidiary (110) (110)       (110)    
Ending balance at Dec. 31, 2025 $ 32,792 $ 32,540 $ 1,579 $ 31,636 $ 0 $ (650) $ (25) $ 252
Ending balance (in shares) at Dec. 31, 2025 2,197,942,874     2,197,942,874        
Ending balance, treasury (in shares) at Dec. 31, 2025         0      
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME, UTILITY - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating Revenues      
Total operating revenues $ 24,935,000 $ 24,419,000 $ 24,428,000
Operating Expenses      
Operating and maintenance 11,349,000 11,808,000 11,924,000
SB 901 securitization charges, net 35,000 33,000 1,267,000
Wildfire-related claims, net of recoveries 100,000 94,000 64,000
Wildfire Fund expense 352,000 383,000 567,000
Depreciation, amortization, and decommissioning 4,634,000 4,189,000 3,738,000
Total operating expenses 20,186,000 19,960,000 21,757,000
Operating Income 4,749,000 4,459,000 2,671,000
Interest income 520,000 604,000 606,000
Interest expense (3,028,000) (3,051,000) (2,850,000)
Other income, net 182,000 300,000 272,000
Income Before Income Taxes 2,423,000 2,312,000 699,000
Income tax benefit (280,000) (200,000) (1,557,000)
Net Income 2,703,000 2,512,000 2,256,000
Preferred stock dividend requirement 110,000 37,000 14,000
Income Available for Common Shareholders 2,593,000 2,475,000 2,242,000
Income Available for Common Shareholders 2,593,000 2,475,000 2,242,000
Utility      
Operating Revenues      
Total operating revenues 24,935,000 24,419,000 24,428,000
Operating Expenses      
Operating and maintenance 11,337,000 11,787,000 11,913,000
SB 901 securitization charges, net 35,000 33,000 1,267,000
Wildfire-related claims, net of recoveries 100,000 94,000 64,000
Wildfire Fund expense 352,000 383,000 567,000
Depreciation, amortization, and decommissioning 4,634,000 4,189,000 3,738,000
Total operating expenses 20,174,000 19,939,000 21,746,000
Operating Income 4,761,000 4,480,000 2,682,000
Interest income 509,000 589,000 593,000
Interest expense (2,713,000) (2,781,000) (2,485,000)
Other income, net 328,000 319,000 293,000
Income Before Income Taxes 2,885,000 2,607,000 1,083,000
Income tax benefit (194,000) (105,000) (1,461,000)
Net Income 3,079,000 2,712,000 2,544,000
Preferred stock dividend requirement 14,000 14,000 14,000
Income Available for Common Shareholders 3,065,000 2,698,000 2,530,000
Income Available for Common Shareholders 3,065,000 2,698,000 2,530,000
Electric      
Operating Revenues      
Total operating revenues 18,318,000 17,811,000 17,424,000
Operating Expenses      
Cost of electricity and natural gas 2,609,000 2,261,000 2,443,000
Electric | Utility      
Operating Revenues      
Total operating revenues 18,318,000 17,811,000 17,424,000
Operating Expenses      
Cost of electricity and natural gas 2,609,000 2,261,000 2,443,000
Natural gas      
Operating Revenues      
Total operating revenues 6,617,000 6,608,000 7,004,000
Operating Expenses      
Cost of electricity and natural gas 1,107,000 1,192,000 1,754,000
Natural gas | Utility      
Operating Revenues      
Total operating revenues 6,617,000 6,608,000 7,004,000
Operating Expenses      
Cost of electricity and natural gas $ 1,107,000 $ 1,192,000 $ 1,754,000
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Net income $ 2,703 $ 2,512 $ 2,256
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively) (11) (7) (16)
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $4, respectively) 5 1 8
Total other comprehensive income (loss) (6) (6) (8)
Comprehensive Income 2,697 2,506 2,248
Utility      
Net income 3,079 2,712 2,544
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively) (8) (8) (12)
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $4, respectively) 5 1 7
Total other comprehensive income (loss) (3) (7) (5)
Comprehensive Income $ 3,076 $ 2,705 $ 2,539
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME, UTILITY (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension and other postretirement benefit plans obligations, tax $ 4 $ 3 $ 6
Net unrealized gain (losses) on available for sale securities, tax 2 0 3
Utility      
Pension and other postretirement benefit plans obligations, tax 4 3 5
Net unrealized gain (losses) on available for sale securities, tax $ 2 $ 0 $ 4
v3.25.4
CONSOLIDATED BALANCE SHEETS, UTILITY - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Current Assets    
Cash and cash equivalents $ 713 $ 940
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates) 259 273
Accounts receivable    
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates) 2,267 2,220
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,463 1,487
Regulatory balancing accounts 6,300 7,227
Other (net of allowance for doubtful accounts of $69 million and $35 million at respective dates) 1,719 1,810
Regulatory assets 305 234
Inventories    
Gas stored underground and fuel oil 75 52
Materials and supplies 745 768
Wildfire Fund asset 297 301
Wildfire self-insurance asset 1,043 905
Other 644 999
Total current assets 15,830 17,216
Property, Plant, and Equipment    
Property, Plant, and Equipment 128,989 118,262
Construction work in progress 4,627 4,458
Financing lease ROU asset and other 2 814
Total property, plant, and equipment 133,618 123,534
Accumulated depreciation (37,270) (35,305)
Net property, plant, and equipment 96,348 88,229
Other Noncurrent Assets    
Regulatory assets 15,981 15,561
Customer credit trust 804 377
Nuclear decommissioning trusts 4,230 3,833
Operating lease ROU asset 450 524
Wildfire Fund asset 3,728 4,070
Other (includes noncurrent accounts receivable of $67 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $18 at respective dates) 4,240 3,850
Total other noncurrent assets 29,433 28,215
TOTAL ASSETS 141,611 133,660
Current Liabilities    
Short-term borrowings 2,675 1,523
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates) 821 2,146
Accounts payable    
Trade creditors 3,353 2,748
Regulatory balancing accounts 3,119 3,169
Other 929 748
Operating lease liabilities 90 85
Financing lease liabilities 0 577
Interest payable (includes $72 million and $91 million related to VIEs at respective dates) 764 760
Wildfire-related claims 524 916
Other 4,025 3,658
Total current liabilities 16,300 16,330
Noncurrent Liabilities    
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) 57,387 53,569
Regulatory liabilities 20,188 19,417
Pension and other postretirement benefits 549 808
Asset retirement obligations 5,439 5,444
Deferred income taxes 4,135 3,082
Operating lease liabilities 360 439
Financing lease liabilities 2 4
Other 4,459 4,166
Total noncurrent liabilities 92,519 86,929
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 31,636 31,555
Reinvested earnings (650) (2,966)
Accumulated other comprehensive loss (25) (19)
Total shareholders’ equity 32,540 30,149
TOTAL LIABILITIES AND EQUITY 141,611 133,660
Variable Interest Entity, Primary Beneficiary    
Current Assets    
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates) 225 263
Accounts receivable    
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates) 1,900 1,900
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,300 1,300
Current Liabilities    
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates) 221 222
Accounts payable    
Interest payable (includes $72 million and $91 million related to VIEs at respective dates) 72 91
Noncurrent Liabilities    
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) 11,700 10,100
Utility    
Current Assets    
Cash and cash equivalents 353 705
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates) 258 272
Accounts receivable    
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates) 2,267 2,220
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,463 1,487
Regulatory balancing accounts 6,300 7,227
Other (net of allowance for doubtful accounts of $69 million and $35 million at respective dates) 1,725 1,810
Regulatory assets 305 234
Inventories    
Gas stored underground and fuel oil 75 52
Materials and supplies 745 768
Wildfire Fund asset 297 301
Wildfire self-insurance asset 1,043 905
Other 643 998
Total current assets 15,474 16,979
Property, Plant, and Equipment    
Property, Plant, and Equipment 128,989 118,262
Construction work in progress 4,626 4,458
Financing lease ROU asset and other 2 814
Total property, plant, and equipment 133,617 123,534
Accumulated depreciation (37,269) (35,304)
Net property, plant, and equipment 96,348 88,230
Other Noncurrent Assets    
Regulatory assets 15,981 15,561
Customer credit trust 804 377
Nuclear decommissioning trusts 4,230 3,833
Operating lease ROU asset 445 519
Wildfire Fund asset 3,728 4,070
Other (includes noncurrent accounts receivable of $67 million and $82 related to VIEs, net of noncurrent allowance for doubtful accounts of $15 million and $18 at respective dates) 4,073 3,697
Total other noncurrent assets 29,261 28,057
TOTAL ASSETS 141,083 133,266
Current Liabilities    
Short-term borrowings 2,675 1,523
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates) 821 2,146
Accounts payable    
Trade creditors 3,352 2,745
Regulatory balancing accounts 3,119 3,169
Other 844 729
Operating lease liabilities 90 85
Financing lease liabilities 0 577
Interest payable (includes $72 million and $91 million related to VIEs at respective dates) 673 667
Wildfire-related claims 524 916
Other 3,710 3,331
Total current liabilities 15,808 15,888
Noncurrent Liabilities    
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) 51,766 47,958
Regulatory liabilities 20,188 19,417
Pension and other postretirement benefits 482 741
Asset retirement obligations 5,439 5,444
Deferred income taxes 4,732 3,632
Operating lease liabilities 355 434
Financing lease liabilities 2 4
Other 4,474 4,198
Total noncurrent liabilities 87,438 81,828
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 37,505 35,930
Reinvested earnings (1,225) (1,940)
Accumulated other comprehensive loss (23) (20)
Total shareholders’ equity 37,837 35,550
TOTAL LIABILITIES AND EQUITY 141,083 133,266
Utility | Variable Interest Entity, Primary Beneficiary    
Current Assets    
Restricted cash and restricted cash equivalents (includes $225 million and $263 million related to VIEs at respective dates) 225 263
Accounts receivable    
Customers (net of allowance for doubtful accounts of $408 million and $418 million at respective dates) (includes $1.9 billion related to VIEs, net of allowance for doubtful accounts of $408 million and $418 million at respective dates) 1,900 1,900
Accrued unbilled revenue (includes $1.3 billion related to VIEs at respective dates) 1,300 1,300
Current Liabilities    
Long-term debt, classified as current (includes $221 million and $222 million related to VIEs at respective dates) 221 222
Accounts payable    
Interest payable (includes $72 million and $91 million related to VIEs at respective dates) 72 91
Noncurrent Liabilities    
Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) $ 11,700 $ 10,100
v3.25.4
CONSOLIDATED BALANCE SHEETS, UTILITY (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Restricted cash and cash equivalents $ 259 $ 273
Allowance for doubtful accounts 408 418
Accounts receivable, after allowance for credit loss, current 2,267 2,220
Accrued unbilled revenue 1,463 1,487
Other (net of allowance for doubtful accounts) 69 35
Long-term debt, classified as current 821 2,146
Interest payable 764 760
Long-term debt $ 57,387 $ 53,569
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) 2,197,942,874 2,193,573,536
Utility    
Restricted cash and cash equivalents $ 258 $ 272
Allowance for doubtful accounts 408 418
Accounts receivable, after allowance for credit loss, current 2,267 2,220
Accrued unbilled revenue 1,463 1,487
Other (net of allowance for doubtful accounts) 69 35
Long-term debt, classified as current 821 2,146
Interest payable 673 667
Long-term debt $ 51,766 $ 47,958
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 $ 225 $ 263
Allowance for doubtful accounts 408 418
Accounts receivable, after allowance for credit loss, current 1,900 1,900
Accrued unbilled revenue 1,300 1,300
Allowance for doubtful accounts, noncurrent 15 18
Noncurrent accounts receivable 67 82
Long-term debt, classified as current 221 222
Interest payable 72 91
Long-term debt 11,700 10,100
Variable Interest Entity, Primary Beneficiary | Utility    
Restricted cash and cash equivalents 225 263
Allowance for doubtful accounts 408 418
Accounts receivable, after allowance for credit loss, current 1,900 1,900
Accrued unbilled revenue 1,300 1,300
Allowance for doubtful accounts, noncurrent 67 82
Noncurrent accounts receivable 15 18
Long-term debt, classified as current 221 222
Interest payable 72 91
Long-term debt $ 11,700 $ 10,100
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Flows from Operating Activities      
Net income $ 2,703 $ 2,512 $ 2,256
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, amortization, and decommissioning 4,634 4,189 3,738
Bad debt expense 402 341 636
Allowance for equity funds used during construction (219) (184) (179)
Deferred income taxes and tax credits, net 1,058 1,098 (765)
Wildfire Fund expense 352 383 568
Other (75) 310 (116)
Effect of changes in operating assets and liabilities:      
Accounts receivable (61) (1,061) (369)
Wildfire-related insurance receivable (167) 318 358
Inventories 0 45 (28)
Accounts payable 176 30 (90)
Wildfire-related claims (392) (506) (489)
Other current assets and liabilities 563 (231) 397
Regulatory assets, liabilities, and balancing accounts, net 173 1,545 (429)
Contributions to Wildfire Fund (193) (193) (193)
Other noncurrent assets and liabilities (238) (561) (548)
Net cash provided by operating activities 8,716 8,035 4,747
Cash Flows from Investing Activities      
Capital expenditures (11,787) (10,369) (9,714)
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952 1,980 2,235
Purchases of nuclear decommissioning trust investments (1,993) (2,002) (2,252)
Proceeds from sales and maturities of customer credit trust investments 435 398 556
Purchases of customer credit investments (742) (519) 0
Proceeds from self-insurance investments 1,181 0 0
Purchases of self-insurance investments (1,384) (898) 0
Other 22 35 13
Net cash used in investing activities (12,316) (11,375) (9,162)
Cash Flows from Financing Activities      
Borrowings under credit facilities 4,790 6,873 10,675
Repayments under credit facilities (1,465) (10,122) (10,540)
Borrowings under term loan 575 0 2,100
Repayments under term loan 0 (2,600) (2,181)
Short-term debt financing, net of issuance costs of $0, $1, and $0 at respective dates 0 999 0
Short-term debt matured (1,000) 0 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $38, $1, and $67 at respective dates 4,962 4,495 5,483
Repayments of long-term debt (3,876) (800) (3,075)
Proceeds from AB 1054 recovery bonds, net issuance costs of $0, $10, and $0 at respective dates 0 1,409 0
Proceeds from DWR loan 0 980 0
Preferred stock dividends paid (97) 0 0
Other (87) (59) (17)
Net cash provided by financing activities 3,359 3,621 4,400
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents (241) 281 (15)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 1,213 932 947
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 972 1,213 932
Less: Restricted cash and restricted cash equivalents (259) (273) (297)
Cash and cash equivalents at December 31 713 940 635
Supplemental disclosures of cash flow information      
Interest, net of amounts capitalized (2,665) (2,421) (2,286)
Supplemental disclosures of noncash investing and financing activities      
Capital expenditures financed through accounts payable 1,859 1,144 1,105
Operating lease liabilities arising from obtaining ROU assets 0 6 269
Financing lease liabilities arising from obtaining ROU assets 0 43 52
Reclassification of operating lease liabilities to financing lease liabilities 0 0 913
DWR loan forgiveness and performance-based disbursements 148 192 214
Capital expenditures financed through current assets and non-current liabilities 592 0 0
AB 1054 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds (88) (46) (38)
SB 901 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds (135) (129) (130)
Utility      
Cash Flows from Operating Activities      
Net income 3,079 2,712 2,544
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, amortization, and decommissioning 4,634 4,189 3,738
Bad debt expense 402 341 636
Allowance for equity funds used during construction (219) (184) (179)
Deferred income taxes and tax credits, net 1,102 1,195 (663)
Wildfire Fund expense 352 383 568
Other (158) 233 (176)
Effect of changes in operating assets and liabilities:      
Accounts receivable (67) (1,060) (361)
Wildfire-related insurance receivable (167) 318 358
Inventories 0 45 (28)
Accounts payable 112 44 (90)
Wildfire-related claims (392) (506) (489)
Other current assets and liabilities 617 (235) 402
Regulatory assets, liabilities, and balancing accounts, net 173 1,545 (429)
Contributions to Wildfire Fund (193) (193) (193)
Other noncurrent assets and liabilities (240) (559) (541)
Net cash provided by operating activities 9,035 8,268 5,097
Cash Flows from Investing Activities      
Capital expenditures (11,787) (10,369) (9,714)
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952 1,980 2,235
Purchases of nuclear decommissioning trust investments (1,993) (2,002) (2,252)
Proceeds from sales and maturities of customer credit trust investments 435 398 556
Purchases of customer credit investments (742) (519) 0
Proceeds from self-insurance investments 1,181 0 0
Purchases of self-insurance investments (1,384) (898) 0
Other 22 35 13
Net cash used in investing activities (12,316) (11,375) (9,162)
Cash Flows from Financing Activities      
Borrowings under credit facilities 4,790 6,873 10,675
Repayments under credit facilities (1,465) (10,122) (10,540)
Borrowings under term loan 575 0 2,100
Repayments under term loan 0 (2,100) 0
Short-term debt financing, net of issuance costs of $0, $1, and $0 at respective dates 0 999 0
Short-term debt matured (1,000) 0 0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $38, $1, and $67 at respective dates 4,962 2,999 5,483
Repayments of long-term debt (3,876) (800) (3,075)
Proceeds from AB 1054 recovery bonds, net issuance costs of $0, $10, and $0 at respective dates 0 1,409 0
Proceeds from DWR loan 0 980 0
Preferred stock dividends paid (14) (14) (14)
Common stock dividends paid (2,350) (2,025) (1,775)
Equity contribution from PG&E Corporation 1,575 5,360 1,290
Other (59) (36) 3
Net cash provided by financing activities 2,915 3,348 3,979
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents (366) 241 (86)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 977 736 822
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 611 977 736
Less: Restricted cash and restricted cash equivalents (258) (272) (294)
Cash and cash equivalents at December 31 353 705 442
Supplemental disclosures of cash flow information      
Interest, net of amounts capitalized (2,359) (2,206) (1,977)
Supplemental disclosures of noncash investing and financing activities      
Capital expenditures financed through accounts payable 1,859 1,144 1,105
Operating lease liabilities arising from obtaining ROU assets 0 1 269
Financing lease liabilities arising from obtaining ROU assets 0 43 52
Reclassification of operating lease liabilities to financing lease liabilities 0 0 913
DWR loan forgiveness and performance-based disbursements 148 192 214
Capital expenditures financed through current assets and non-current liabilities 592 0 0
Utility | AB 1054 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds (88) (46) (38)
Utility | SB 901 Recovery Bonds      
Cash Flows from Financing Activities      
Repayments of recovery bonds $ (135) $ (129) $ (130)
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS, UTILITY (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Issuance costs for short-term debt $ 0 $ 1 $ 0
Premium, discount, and issuance costs on proceeds from long-term debt 38 5 67
Utility      
Issuance costs for short-term debt 0 1 0
Premium, discount, and issuance costs on proceeds from long-term debt 38 1 67
AB 1054 Recovery Bonds      
Financing fees 0 10 0
AB 1054 Recovery Bonds | Utility      
Financing fees $ 0 $ 10 $ 0
v3.25.4
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, 2022 $ 23,075   $ 22,823 $ 27,484 $ 0 $ 258 $ 32,887 $ 1,322 $ 29,280 $ (7,542) $ (3,368) $ (5) $ (8)
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income 2,256 $ 2,544 2,256 2,544           2,256 2,544    
Other comprehensive loss (8) (5) (8) (5)               (8) (5)
Equity contribution       1,290         1,290        
Preferred stock dividend requirement       (14)             (14)    
Common stock dividend (21)   (21) (1,775)           (21) (1,775)    
Ending balance at Dec. 31, 2023 25,292   25,040 29,524 0 258 30,374 1,322 30,570 (5,321) (2,613) (13) (13)
Increase (Decrease) in Stockholders' Equity [Roll Forward]                          
Net income 2,512 2,712 2,512 2,712           2,512 2,712    
Other comprehensive loss (6) (7) (6) (7)               (6) (7)
Equity contribution       5,360         5,360        
Preferred stock dividend requirement       (14)             (14)    
Common stock dividend (120)   (120) (2,025)           (120) (2,025)    
Ending 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 2,703 3,079 2,703 3,079           2,703 3,079    
Other comprehensive loss (6) $ (3) (6) (3)               (6) (3)
Equity contribution       1,575         1,575        
Preferred stock dividend requirement       (14)             (14)    
Common stock dividend (277)   (277) (2,350)           (277) (2,350)    
Ending 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)
v3.25.4
ORGANIZATION AND BASIS OF PRESENTATION
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
ORGANIZATION AND BASIS OF PRESENTATION ORGANIZATION AND BASIS OF PRESENTATION
Organization and Basis of Presentation

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

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

The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Regulation and Regulated Operations

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

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

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

Net income (loss) is the measure that the chief operating decision maker 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 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 Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker 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.
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2025 and 2024, the Utility also held $258 million and $272 million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.
Revenue Recognition

Revenue from Contracts with Customers

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

Regulatory Balancing Account Revenue

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

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass 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:
Year Ended December 31,
(in millions)202520242023
Electric
Revenue from contracts with customers
   Residential$6,976 $7,504 $6,041 
   Commercial7,022 7,201 5,643 
   Industrial1,929 2,065 1,784 
   Agricultural1,825 1,815 1,413 
   Public street and highway lighting105 103 83 
   Other, net (1)
72 (47)136 
      Total revenue from contracts with customers - electric17,929 18,641 15,100 
Regulatory balancing accounts (2)
389 (830)2,324 
Total electric operating revenue$18,318 $17,811 $17,424 
Natural gas
Revenue from contracts with customers
   Residential$3,651 $3,089 $3,686 
   Commercial1,074 984 1,052 
   Transportation service only1,937 1,815 1,603 
   Other, net (1)
101 159 (145)
      Total revenue from contracts with customers - gas6,763 6,047 6,196 
Regulatory balancing accounts (2)
(146)561 808 
Total natural gas operating revenue6,617 6,608 7,004 
Total operating revenues$24,935 $24,419 $24,428 
(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 December 31, 2025, PG&E Corporation and the Utility have 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 $402 million, $341 million, and $636 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2025, 2024, and 2023, 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 December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively.
Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 14 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 December 31, 2025, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Emission Allowances

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

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or for use as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” below.  The Utility’s estimated service lives of its property, plant, and equipment were as follows:
 Estimated ServiceBalance at December 31,
(in millions, except estimated service lives)Lives (years)20252024
Electricity generating facilities (1)
1 to 75
$11,986 $11,420 
Electricity distribution facilities
5 to 70
57,174 49,821 
Electricity transmission facilities
5 to 80
20,959 18,481 
Natural gas distribution facilities
15 to 60
18,240 17,213 
Natural gas transmission and storage facilities
15 to 68
11,315 11,117 
General plant and other
5 to 50
9,315 10,210 
Financing lease2 814 
Construction work in progress4,626 4,458 
Total property, plant, and equipment133,617 123,534 
Accumulated depreciation(37,269)(35,304)
Net property, plant, and equipment (2)
$96,348 $88,230 
(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. See Note 15 below. Nuclear generating facilities have been fully depreciated by December 31, 2025.
(2) Includes $2.9 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and in a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.77% in 2025 and 3.61% in 2024. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired asset is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.
Allowance for Funds Used During Construction

AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $88 million and $219 million during 2025, $111 million and $184 million during 2024, and $82 million and $179 million during 2023.
Asset Retirement Obligations

The following table summarizes the changes in ARO during 2025 and 2024, including nuclear decommissioning obligations:
(in millions)20252024
ARO liability at beginning of year$5,444 $5,512 
Revision in estimated cash flows(274)(290)
Accretion290 269 
Liabilities settled(21)(47)
ARO liability at end of year$5,439 $5,444 

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below.

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

The total nuclear decommissioning obligation was $4.2 billion as of December 31, 2025 and $4.0 billion as of December 31, 2024 based on the cost study performed as part of the 2021 NDCTP. The Utility’s ARO assumes that DCPP operates until 2030. The ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.
Disallowance of Plant Costs

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

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

The cost of debt and equity securities sold by the trust is determined by specific identification. Gains on the nuclear decommissioning trust investments are refundable to customers through rates, and losses are recoverable through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.
Government Assistance

The Utility participated in various government assistance programs during the year ended December 31, 2025, 2024, and 2023. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the year ended December 31, 2025, the Consolidated Statements of Income reflected $13 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

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 Consolidated Financial Statements:
(in millions)
202520242023
Long-term debt:
Beginning Balance - DWR loan outstanding
$886 $98 $312 
Proceeds received
— 980 — 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
(21)(117)(124)
Operating and maintenance expense - Loan forgiveness and other adjustments
(127)(75)(90)
Long-term debt:
Ending Balance - DWR loan outstanding$738 $886 $98 

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 years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $65 million, $265 million, and $115 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 years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $69 million, $138 million, and $76 million, respectively, as deductions 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 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 year ended December 31, 2025 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2025 and December 31, 2024, the SPV had net accounts receivable of $3.2 billion, and outstanding borrowings of $1.8 billion and $0 million, respectively, 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 year ended December 31, 2025 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 December 31, 2025 and December 31, 2024, PG&E Recovery Funding LLC had outstanding borrowings of $3.1 billion and $3.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the 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 year ended December 31, 2025 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 $7.5 billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion and $7.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

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 December 31, 2025, 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 December 31, 2025, 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.

As of December 31, 2025, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $377 million in Other noncurrent liabilities, $297 million in Current assets - Wildfire Fund asset, and $3.7 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the years ended December 31, 2025 and 2024, the Utility recorded amortization and accretion expense of $352 million and $383 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 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 14 below.
Oakland Headquarters Purchase

On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Oakland General Office. The purchase price was $906 million, of which the Utility had prepaid a total of $400 million. At closing, the Utility assumed a $172 million noncurrent liability for a property assessment carried by the property and paid an additional $349 million, which was adjusted for closing costs. The cash payment is included within the Capital expenditures line item in PG&E Corporation’s and Utility’s Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities.
Other Accounting Policies

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

The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2025 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
Beginning balance$(35)$18 $3 $(14)
Other comprehensive income before reclassifications:
Unrealized loss on investments (net of taxes of $0, $0 and $2, respectively)
— — 5 5 
Unrecognized net actuarial gain (loss) (net of taxes of $84, $25 and $0, respectively)
215 (64)— 151 
Regulatory account transfer (net of taxes of $89, $25 and $0, respectively)
(228)64 — (164)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)
(2)2 — — 
Amortization of net actuarial (gain) loss (net of taxes of $1, $6 and $0, respectively) (1)
1 (15)— (14)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)
2 14 — 16 
Net current period other comprehensive income(12)1 5 (6)
Ending balance$(47)$19 $8 $(20)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.
(2) Includes amounts related to the customer credit trust and self-insurance.
The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2024 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
Beginning balance$(28)$18 $2 $(8)
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively)
— — 1 1 
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively)
(268)29 — (239)
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively)
260 (29)— 231 
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)
(2)2 — — 
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively)(1)
1 (16)— (15)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)
2 14 — 16 
Net current period other comprehensive income (loss)(7)— 1 (6)
Ending balance$(35)$18 $3 $(14)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.
(2) Includes amounts related to the customer credit trust and wildfire self-insurance.
Recognition of Lease Assets and Liabilities

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

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless it can ascertain an implicit discount rate from the leasing arrangement. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense as paid in conformity with ratemaking.

Financing Leases

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2025, 2024 and 2023, the Utility made total fixed cash payments of $26 million, $315 million, and $142 million, respectively, for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. The majority of the Utility’s financing lease ROU assets and lease liabilities related to the lease of the Oakland General Office, which the Utility purchased on June 3, 2025. See “Oakland Headquarters Purchase” above.

At December 31, 2025 and 2024, the Utility’s financing leases had a weighted average remaining lease term of 4.1 years and 0.5 years and a weighted average discount rate of 4.6% and 6.2%, respectively.
The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
Year Ended December 31,
(in millions)202520242023
Financing lease fixed cost:
Amortization of ROU assets$583 $274 $115 
Interest on lease liabilities16 42 27 
Financing lease variable cost(1)9 3 
Total financing lease costs$598 $325 $145 

As of December 31, 2025, the Utility’s future expected financing lease payments are not material.

Operating Leases

Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2025, 2024, and 2023, the Utility made total cash payments, including fixed and variable, of $1.6 billion, $1.6 billion, and $1.9 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows.

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

At December 31, 2025 and 2024, the Utility’s operating leases had a weighted average remaining lease term of 7.1 years and 7.5 years and a weighted average discount rate of 6.6% and 6.5%, respectively.

The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
Year Ended December 31,
(in millions)202520242023
Operating lease fixed cost$115 $116 $269 
Operating lease variable cost1,487 1,524 1,632 
Total operating lease costs$1,602 $1,640 $1,901 

At December 31, 2025, the Utility’s future expected operating lease payments were as follows:
(in millions)December 31, 2025
2026$115 
2027112 
202898 
202964 
203034 
Thereafter165 
Total lease payments588 
Less imputed interest(143)
Total$445 
Recently Adopted Accounting Standards

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amended the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. PG&E Corporation and the Utility have applied enhanced disclosure requirements, including, but not limited to, those with respect to PG&E Corporation and the Utility’s income tax rate reconciliation and income taxes paid. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025 and PG&E Corporation and the Utility have applied the enhanced disclosure requirements of ASU 2023-09 on a retrospective basis.

Derivatives and Hedging and Revenue from Contracts with Customers

In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606), which amended the existing guidance to (a) reduce the cost and complexity of evaluating whether contracts with features based on the operations or activities of one of the parties to the contract are derivatives, (b) better portray the economics of those contracts in the financial statements, and (c) reduce diversity in practice resulting from the broad application of the current guidance and changing business environment. The amendments also are expected to reduce diversity in practice by clarifying the applicability of Topic 606, Revenue from Contracts with Customers, to share-based noncash consideration from a customer for the transfer of goods or services. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2025. The adoption of this ASU did not have a significant impact on PG&E Corporation and the Utility’s 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 Consolidated Financial Statements and related disclosures.

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 will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, 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 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 Consolidated Financial Statements and related disclosures.
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
 12 Months Ended
Dec. 31, 2025
Regulated Operations [Abstract]  
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
Regulatory Assets

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. The Utility does not earn a return on regulatory assets if the related costs do not accrue interest.

Noncurrent regulatory assets are comprised of the following:
 Balance at December 31,Recovery
Period
(in millions)20252024
Pension benefits (1)
$400 $673 Indefinitely
Environmental compliance costs1,158 1,172 32 years
Price risk management100 167 
up to 15.5 years
Catastrophic event memorandum account (2)
666 742 Various
Wildfire-related accounts (3)
1,626 1,697 Various
Deferred income taxes (4)
6,157 4,771 Various
Financing costs (5)
202 216 Various
SB 901 securitization (6)
5,089 5,194 27 years
General rate case memorandum accounts (7)
— 95 Various
Other (8)
583 834 Various
Total noncurrent regulatory assets$15,981 $15,561  
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities.
(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FRMMA, WMPMA, WMBA, VMBA and MGMA.
(4) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings.
(6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below.
(7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 included revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022.
(8) The balance as of December 31, 2025 includes revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014.
Regulatory Liabilities

Current Regulatory Liabilities

At December 31, 2025 and 2024, the Utility had current regulatory liabilities of $965 million and $1.2 billion respectively. At December 31, 2025, current regulatory liabilities consisted primarily of billed revenues exceeding FERC TO formula rate revenue requirements. Current regulatory liabilities are included within Current liabilities - Other in the Consolidated Balance Sheets.

Noncurrent Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:
 Balance at December 31,
(in millions)20252024
Cost of removal obligations (1)
$9,488 $8,943 
Public purpose programs (2)
1,169 1,112 
Employee benefit plans (3)
1,043 1,088 
Transmission tower wireless licenses (4)
257 306 
SFGO sale (5)
— 79 
SB 901 securitization (6)
6,010 6,295 
Wildfire self-insurance (7)
1,035 804 
Other (8)
1,186 790 
Total noncurrent regulatory liabilities
$20,188 $19,417 
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected through rates for expected costs to remove assets.
(2) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(3) Represents cumulative differences between incurred costs and amounts collected through rates for post-retirement medical, post-retirement life, and long-term disability plans.
(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042.
(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.
(6) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization. See Note 5 below.
(7) Represents amounts collected through rates designated for wildfire self-insurance, plus earnings on investments and less operating expenses of wildfire self-insurance. Balance at December 31, 2025 includes amounts collected through both CPUC and FERC rates. Balance at December 31, 2024 includes only amounts collected through CPUC rates. See Note 14 below.
(8) Includes amounts collected through FERC rates designated for wildfire self-insurance at December 31, 2024. See Note 14 below.
Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts fluctuate during the year based on seasonal electric and gas usage and timing differences between when costs are incurred and customer revenues are collected.

Some regulatory balancing accounts receivable earn interest which is reflected in Interest income in the Consolidated Statements of Income. Some regulatory balancing accounts payable accrue interest which is reflected in Interest expense in the Consolidated Statements of Income. Interest income from balancing accounts receivable was $419 million, $537 million, and $547 million for the years ended December 31, 2025, 2024, and 2023, respectively. Interest expense from balancing accounts payable was $223 million, $323 million, and $257 million for the years ended December 31, 2025, 2024, and 2023, respectively.
Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable
Balance at December 31,
(in millions)20252024
Electric distribution (1)
$1,465 $1,591 
Electric transmission (2)
122 117 
Gas distribution and transmission (3)
142 387 
Energy procurement (4)
2,711 1,066 
Public purpose programs (5)
151 162 
Wildfire-related accounts (6)
84 979 
Insurance premium costs (7)
— 38 
Residential uncollectibles balancing accounts (8)
278 260 
Catastrophic event memorandum account (9)
181 500 
General rate case memorandum accounts (10)
— 1,113 
Other1,166 1,014 
Total regulatory balancing accounts receivable$6,300 $7,227 

Payable
Balance at December 31,
(in millions)20252024
Electric transmission (2)
$37 $883 
Gas distribution and transmission (3)
78 72 
Energy procurement (4)
1,502 329 
Public purpose programs (5)
472 882 
SFGO sale83 93 
Wildfire-related accounts (6)
338 337 
Nuclear decommissioning adjustment mechanism (11)
1 23 
Other608 550 
Total regulatory balancing accounts payable$3,119 $3,169 
(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.
(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases.
(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings.
(4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities.
(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.
(6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA.
(7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC.
(8) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to limits on electric and gas service disconnections for residential customers.
(9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, 2022 WMCE final decision, and 2023 WMCE final decision.
(10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.
(11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision.
v3.25.4
DEBT
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
DEBT DEBT
Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2025:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJune 2030$5,400 
(1)
$(1,575)$(639)$3,186 
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 $(3,325)$(639)$3,836 
(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.

Utility

On April 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity date to April 10, 2026. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 23, 2025, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 21, 2030, (ii) increase the aggregate commitments from $4.4 billion to $5.4 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2025, the Utility and the SPV amended the existing $1.5 billion Receivables Securitization Program to, among other things, (i) extend the scheduled termination date from June 26, 2026 to June 25, 2027 and (ii) allow the Utility and the SPV to request an increase to the commitments by an additional aggregate amount of up to $250 million, subject to the satisfaction of certain terms and conditions.

On September 24, 2025, the Utility entered into a Term Loan Credit Agreement, pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $500 million (the “Term Loan”). The Term Loan bears interest based on the Utility’s election of either (1) Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%. The Utility borrowed the entire amount of the Term Loan on September 24, 2025. The Term Loan has a maturity date of September 23, 2026.

On December 19, 2025, the Utility amended its existing $525 million term loan agreement to, among other things, (i) increase the borrowing capacity to $600 million, (ii) extend the maturity date to December 18, 2026 and (iii) revise the interest rate based on the Utility’s election of either (1) the Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%.

PG&E Corporation

On June 23, 2025, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2028, (ii) increase the aggregate commitments from $500 million to $650 million and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.
Long-Term Debt Issuances and Redemptions

Utility

On February 24, 2025, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of 5.700% First Mortgage Bonds due 2035 and (ii) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for (i) the repayment of all of its $600 million aggregate principal amount of 3.500% First Mortgage Bonds due June 15, 2025, and (ii) the repayment of all of its $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 4, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, and (ii) $850 million aggregate principal amount of 6.000% First Mortgage Bonds due 2035. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026.

On October 2, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, (ii) $850 million aggregate principal amount of 5.050% First Mortgage Bonds due 2032, and (iii) $750 million aggregate principal amount of 6.100% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.
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”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

•during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or

•upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.
On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2025, none of the conditions allowing holders of the Convertible Notes to convert had been met.

The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2025 and 2024, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion and $2.13 billion, with unamortized debt issuance costs of $13 million and $20 million, respectively, in Long-term debt. For the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $91 million, $98 million, and $7 million, respectively.
The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt:
Balance at
(in millions)Contractual Interest RatesDecember 31, 2025December 31, 2024
PG&E Corporation
Convertible Notes due 20274.25%$2,150 $2,150 
Senior Secured Notes due 20285.00%1,000 1,000 
Senior Secured Notes due 20305.25%1,000 1,000 
Junior Subordinated Notes due 20557.38%1,500 1,500 
Unamortized discount, premium and debt issuance costs, net(29)(39)
Total PG&E Corporation Long-Term Debt5,621 5,611 
Utility
First Mortgage Bonds - Stated Maturity:
2025
3.45% - 4.95%
— 1,925 
2026
 2.95%
600 2,551 
2027
2.10% - 5.45%
3,000 3,000 
2028
3.00% - 5.00%
2,775 1,975 
2029
4.20% - 6.10%
2,100 2,100 
2030
 4.55%
3,100 3,100 
2031
2.50% - 3.25%
3,000 3,000 
2032
4.40% - 5.90%
1,900 1,050 
2033
6.15% - 6.40%
1,900 1,900 
2034
5.80% - 6.95%
1,900 1,900 
2035
5.70% - 6.00%
1,850 — 
2040
3.30% - 4.50%
2,951 2,951 
2041
4.20% - 4.50%
700 700 
2042
3.75% - 4.45%
750 750 
2043
4.60%
375 375 
2044
4.75%
675 675 
2045
4.30%
600 600 
2046
4.00% - 4.25%
1,050 1,050 
2047
3.95%
850 850 
2050
3.50% - 4.95%
5,025 5,025 
2052
5.25%
550 550 
2053
6.70% - 6.75%
2,300 2,300 
20545.90%750 750 
2055
6.10% - 6.15%
1,500 — 
Less: current portion, net of unamortized discount and debt issuance costs(600)(1,924)
Unamortized discount, premium and debt issuance costs, net(247)(226)
Total Utility First Mortgage Bonds39,354 36,927 
Recovery Bonds (1)
10,145 10,367 
         Less: current portion(221)(222)
DWR Loan (2)
738 886 
Credit Facilities
Receivables Securitization Program - Stated Maturity: 2027
variable rate (3)
1,750 — 
Total Utility Long-Term Debt51,766 47,958 
Total PG&E Corporation Consolidated Long-Term Debt$57,387 $53,569 
(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.
(3) At December 31, 2025, the contractual SOFR-based interest rate on the Receivables Securitization Program was 5.31%.
Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2025 are reflected in the table below:
       
(in millions, except interest rates)20262027202820292030ThereafterTotal
PG&E Corporation
Average fixed interest rate— %4.25 %5.00 %— %5.25 %7.38 %5.39 %
Fixed rate obligations$— $2,150 $1,000 $— $1,000 $1,500 $5,650 
Utility (1)
Average fixed interest rate2.95 %3.22 %3.99 %5.52 %4.55 %4.90 %4.69 %
Fixed rate obligations$600 $3,000 $2,775 $2,100 $3,100 $28,626 $40,201 
Variable interest rate as of December 31, 2025
— %5.31 %— %— %— %— %5.31 %
Variable rate obligations
$— $1,750 $— $— $— $— $1,750 
Recovery Bonds (2)
AB 1054 obligations$81 $84 $88 $91 $95 $2,633 $3,072 
SB 901 obligations140 146 152 159 165 6,311 7,073 
Total consolidated debt$821 $7,130 $4,015 $2,350 $4,360 $39,070 $57,746 
(1) The balance excludes the DWR loan, see Note 2 - Government Assistance.
(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
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 11 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 Consolidated Statements of Income and had no net impact on Operating revenues for the year ended December 31, 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 December 31, 2025, 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 Consolidated Statements of Income. During the years ended December 31, 2025 and 2024, the Utility recorded $302 million and $328 million, respectively, for amortization of the regulatory asset and liability in the 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)
20252024
Balance at January 1
$5,194 $5,249 
Amortization
(105)(55)
Balance at December 31
$5,089 $5,194 
SB 901 securitization regulatory liability
(in millions)
20252024
Balance at January 1
$(6,295)$(6,628)
Amortization
407 383 
Additions(1)
(122)(50)
Balance at December 31
$(6,010)$(6,295)
(1) Includes $87 million and $16 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2025 and 2024, respectively.
v3.25.4
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST DEBT
Credit Facilities and Term Loans

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of December 31, 2025:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJune 2030$5,400 
(1)
$(1,575)$(639)$3,186 
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 $(3,325)$(639)$3,836 
(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.

Utility

On April 11, 2025, the Utility amended its existing $525 million term loan agreement to extend the maturity date to April 10, 2026. The loan bears interest based on the Utility’s election of either (1) Term SOFR (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375% or (2) the alternative base rate plus an applicable margin of 0.375%.

On June 23, 2025, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 21, 2030, (ii) increase the aggregate commitments from $4.4 billion to $5.4 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2025, the Utility and the SPV amended the existing $1.5 billion Receivables Securitization Program to, among other things, (i) extend the scheduled termination date from June 26, 2026 to June 25, 2027 and (ii) allow the Utility and the SPV to request an increase to the commitments by an additional aggregate amount of up to $250 million, subject to the satisfaction of certain terms and conditions.

On September 24, 2025, the Utility entered into a Term Loan Credit Agreement, pursuant to which the lenders made available to the Utility term loans in the aggregate principal amount equal to $500 million (the “Term Loan”). The Term Loan bears interest based on the Utility’s election of either (1) Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%. The Utility borrowed the entire amount of the Term Loan on September 24, 2025. The Term Loan has a maturity date of September 23, 2026.

On December 19, 2025, the Utility amended its existing $525 million term loan agreement to, among other things, (i) increase the borrowing capacity to $600 million, (ii) extend the maturity date to December 18, 2026 and (iii) revise the interest rate based on the Utility’s election of either (1) the Term SOFR plus an applicable margin of 1.250% or (2) the alternative base rate plus an applicable margin of 0.250%.

PG&E Corporation

On June 23, 2025, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2028, (ii) increase the aggregate commitments from $500 million to $650 million and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.
Long-Term Debt Issuances and Redemptions

Utility

On February 24, 2025, the Utility completed the sale of (i) $1.0 billion aggregate principal amount of 5.700% First Mortgage Bonds due 2035 and (ii) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for (i) the repayment of all of its $600 million aggregate principal amount of 3.500% First Mortgage Bonds due June 15, 2025, and (ii) the repayment of all of its $450 million aggregate principal amount of 4.950% First Mortgage Bonds due June 8, 2025. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 4, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, and (ii) $850 million aggregate principal amount of 6.000% First Mortgage Bonds due 2035. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026.

On October 2, 2025, the Utility completed the sale of (i) $400 million aggregate principal amount of 5.000% First Mortgage Bonds due 2028, (ii) $850 million aggregate principal amount of 5.050% First Mortgage Bonds due 2032, and (iii) $750 million aggregate principal amount of 6.100% First Mortgage Bonds due 2055. The Utility used the net proceeds of such issuances for repayment of a portion of its $1.9 billion aggregate principal amount of 3.15% First Mortgage Bonds due January 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.
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”). The Convertible Notes bear interest at an annual rate of 4.25% with interest payable semiannually in arrears on June 1 and December 1 of each year, beginning on June 1, 2024. The net proceeds from these offerings were approximately $2.12 billion, after deducting the initial purchasers’ discounts and commissions and PG&E Corporation’s offering expenses. PG&E Corporation used the net proceeds to prepay $2.15 billion outstanding under its term loan agreement.

The Convertible Notes are governed by an indenture (the “Convertible Notes Indenture”). The Convertible Notes Indenture contains limited covenants, including those restricting PG&E Corporation’s ability and certain of PG&E Corporation’s subsidiaries’ ability to create liens, engage in sale and leaseback transactions or merge or consolidate with another entity.

Prior to the close of business on the business day immediately preceding September 1, 2027, the Convertible Notes will be convertible by means of Combination Settlement (as described below) when the following conditions are met:

•during any calendar quarter commencing after the calendar quarter ending on March 31, 2024, if the last reported sale price of PG&E Corporation’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on, and including the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day;

•during the five consecutive business day period immediately after any 10 consecutive trading day period (“measurement period”) in which the trading price per $1,000 principal amount of Convertible Notes, as determined following a request by a holder of Convertible Notes in accordance with the procedures described in the Convertible Notes Indenture, for each trading day of the measurement period was less than 90% of the product of the last reported sale price of PG&E Corporation’s common stock and the conversion rate on each such trading day; or

•upon specified distributions and corporate events described in the Convertible Notes Indenture.

On or after September 1, 2027, the Convertible Notes are convertible by means of Combination Settlement (as described below) by holders at any time in whole or in part until the close of business on the business day immediately preceding the maturity date.
On December 8, 2023, PG&E Corporation delivered an irrevocable notice (the “Irrevocable Notice”) to the Trustee under the Convertible Notes Indenture to irrevocably fix the Settlement Method upon conversion to Combination Settlement with a Specified Dollar Amount (each as defined in the Convertible Notes Indenture) per $1,000 principal amount of Convertible Notes at or above $1,000 for any conversions of the Convertible Notes occurring subsequent to the delivery of such Irrevocable Notice on December 8, 2023; provided that in no event shall the Specified Dollar Amount per $1,000 principal amount of Convertible Notes be less than $1,000.

The conversion rate for the Convertible Notes is initially 43.146 shares of common stock per $1,000 principal amount of the Convertible Notes (equivalent to an initial conversion price of approximately $23.18 per share of PG&E Corporation common stock). The conversion rate and the corresponding conversion price are subject to adjustment in connection with some events but will not be adjusted for any accrued and unpaid interest. PG&E Corporation may not redeem the Convertible Notes prior to the maturity date.

If PG&E Corporation undergoes a Fundamental Change (other than an Exempted Fundamental Change, each as defined in the Convertible Notes Indenture), subject to certain conditions, holders may require PG&E Corporation to repurchase for cash all or any portion of their Convertible Notes at a repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the Fundamental Change Repurchase Date (as defined in the Convertible Notes Indenture). As of December 31, 2025, none of the conditions allowing holders of the Convertible Notes to convert had been met.

The Convertible Notes are accounted for in accordance with ASC Subtopic 470-20, Debt with Conversion and Other Options. Pursuant to ASC Subtopic 470-20, debt with an embedded conversion feature should be accounted for in its entirety as a liability, and no portion of the proceeds from the issuance of the convertible debt instrument should be accounted for as attributable to the conversion feature unless the conversion feature is required to be accounted for separately as an embedded derivative or the conversion feature results in a premium that is subject to the guidance in ASC 470. The Convertible Notes issued are accounted for as a liability with no portion of the proceeds attributable to the conversion options as the conversion feature did not require separate accounting as a derivative, and the Convertible Notes did not involve a premium subject to the guidance in ASC 470.

As of December 31, 2025 and 2024, the Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion and $2.13 billion, with unamortized debt issuance costs of $13 million and $20 million, respectively, in Long-term debt. For the years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected the total interest expense of approximately $91 million, $98 million, and $7 million, respectively.
The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt:
Balance at
(in millions)Contractual Interest RatesDecember 31, 2025December 31, 2024
PG&E Corporation
Convertible Notes due 20274.25%$2,150 $2,150 
Senior Secured Notes due 20285.00%1,000 1,000 
Senior Secured Notes due 20305.25%1,000 1,000 
Junior Subordinated Notes due 20557.38%1,500 1,500 
Unamortized discount, premium and debt issuance costs, net(29)(39)
Total PG&E Corporation Long-Term Debt5,621 5,611 
Utility
First Mortgage Bonds - Stated Maturity:
2025
3.45% - 4.95%
— 1,925 
2026
 2.95%
600 2,551 
2027
2.10% - 5.45%
3,000 3,000 
2028
3.00% - 5.00%
2,775 1,975 
2029
4.20% - 6.10%
2,100 2,100 
2030
 4.55%
3,100 3,100 
2031
2.50% - 3.25%
3,000 3,000 
2032
4.40% - 5.90%
1,900 1,050 
2033
6.15% - 6.40%
1,900 1,900 
2034
5.80% - 6.95%
1,900 1,900 
2035
5.70% - 6.00%
1,850 — 
2040
3.30% - 4.50%
2,951 2,951 
2041
4.20% - 4.50%
700 700 
2042
3.75% - 4.45%
750 750 
2043
4.60%
375 375 
2044
4.75%
675 675 
2045
4.30%
600 600 
2046
4.00% - 4.25%
1,050 1,050 
2047
3.95%
850 850 
2050
3.50% - 4.95%
5,025 5,025 
2052
5.25%
550 550 
2053
6.70% - 6.75%
2,300 2,300 
20545.90%750 750 
2055
6.10% - 6.15%
1,500 — 
Less: current portion, net of unamortized discount and debt issuance costs(600)(1,924)
Unamortized discount, premium and debt issuance costs, net(247)(226)
Total Utility First Mortgage Bonds39,354 36,927 
Recovery Bonds (1)
10,145 10,367 
         Less: current portion(221)(222)
DWR Loan (2)
738 886 
Credit Facilities
Receivables Securitization Program - Stated Maturity: 2027
variable rate (3)
1,750 — 
Total Utility Long-Term Debt51,766 47,958 
Total PG&E Corporation Consolidated Long-Term Debt$57,387 $53,569 
(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.
(3) At December 31, 2025, the contractual SOFR-based interest rate on the Receivables Securitization Program was 5.31%.
Contractual Repayment Schedule

PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2025 are reflected in the table below:
       
(in millions, except interest rates)20262027202820292030ThereafterTotal
PG&E Corporation
Average fixed interest rate— %4.25 %5.00 %— %5.25 %7.38 %5.39 %
Fixed rate obligations$— $2,150 $1,000 $— $1,000 $1,500 $5,650 
Utility (1)
Average fixed interest rate2.95 %3.22 %3.99 %5.52 %4.55 %4.90 %4.69 %
Fixed rate obligations$600 $3,000 $2,775 $2,100 $3,100 $28,626 $40,201 
Variable interest rate as of December 31, 2025
— %5.31 %— %— %— %— %5.31 %
Variable rate obligations
$— $1,750 $— $— $— $— $1,750 
Recovery Bonds (2)
AB 1054 obligations$81 $84 $88 $91 $95 $2,633 $3,072 
SB 901 obligations140 146 152 159 165 6,311 7,073 
Total consolidated debt$821 $7,130 $4,015 $2,350 $4,360 $39,070 $57,746 
(1) The balance excludes the DWR loan, see Note 2 - Government Assistance.
(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
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 11 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 Consolidated Statements of Income and had no net impact on Operating revenues for the year ended December 31, 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 December 31, 2025, 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 Consolidated Statements of Income. During the years ended December 31, 2025 and 2024, the Utility recorded $302 million and $328 million, respectively, for amortization of the regulatory asset and liability in the 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)
20252024
Balance at January 1
$5,194 $5,249 
Amortization
(105)(55)
Balance at December 31
$5,089 $5,194 
SB 901 securitization regulatory liability
(in millions)
20252024
Balance at January 1
$(6,295)$(6,628)
Amortization
407 383 
Additions(1)
(122)(50)
Balance at December 31
$(6,010)$(6,295)
(1) Includes $87 million and $16 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2025 and 2024, respectively.
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION
 12 Months Ended
Dec. 31, 2025
Common Stock And Share-Based Compensation [Abstract]  
COMMON STOCK AND SHARE-BASED COMPENSATION COMMON STOCK AND SHARE-BASED COMPENSATION
PG&E Corporation had 2,197,942,874 shares of common stock outstanding at December 31, 2025, excluding 477,743,590 shares of common stock owned by the Utility. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2025.

On December 4, 2024, PG&E Corporation issued 55,961,070 shares of common stock, no par value, for cash proceeds of approximately $1.13 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.
Dividends

CPUC holding company rules require that the Utility’s dividend policy be established by the Utility’s Board of Directors on the same basis as if the Utility were a stand-alone utility company, and that the capital requirements of Utility, as deemed to be necessary to meet the Utility’s electricity service obligations, receive first priority from the Boards of Directors of both PG&E Corporation and the Utility. The CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average.

California law requires that a corporation must pass either a retained earnings test or an asset to liabilities ratio test to declare a dividend, ensuring it can meet its liabilities as they mature.

Additionally, neither PG&E Corporation nor the Utility may pay common stock dividends unless all cumulative preferred dividends on PG&E Corporation’s Mandatory Convertible Preferred Stock and the Utility’s preferred stock, respectively, have been paid.

Subject to the foregoing restrictions, 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 on common stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation common stock$0.025 $55 November 29, 2024December 31, 2024January 15, 2025
0.02555 February 20, 2025March 31, 2025April 15, 2025
0.02555 May 22, 2025June 30, 2025July 15, 2025
0.02555 September 18, 2025September 30, 2025October 15, 2025
0.05110 December 11, 2025December 31, 2025January 15, 2026
Utility common stock
(1)
575 February 20, 2025
(1)
March 18, 2025
(1)
575 May 22, 2025
(1)
May 30, 2025
(1)
575 September 18, 2025
(1)
September 26, 2025
(1)
625 December 11, 2025
(1)
December 18, 2025
(1) PG&E Corporation owns all of the outstanding shares of Utility common stock.
Long-Term Incentive Plans

The LTIP (i.e., the PG&E Corporation 2014 LTIP or the PG&E Corporation 2021 LTIP, as applicable) permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 91 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the LTIP, of which 51,401,320 shares were available for future awards at December 31, 2025.

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards:
(in millions)
202520242023
Restricted stock units80 67 64 
Performance shares54 31 27 
Total compensation expense (pre-tax)$134 $98 $91 
Total compensation expense (after-tax)$97 $71 $65 

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

Stock Options

The exercise price of stock options granted under the LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the grant date.  Stock options generally have a 10-year term and vest over three years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2025, there were no unrecognized compensation costs related to nonvested stock options for PG&E Corporation.

The fair value of each stock option on the grant date is estimated using the Black-Scholes valuation method. No stock options were granted in 2025 or 2024.

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

There was no tax benefit recognized from stock options for the year ended December 31, 2025.

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2025:
Number of
Stock Options		Weighted Average Grant-
Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1743,963 $10.23 
Granted (1)
— — 
Exercised— — 
Forfeited or expired(111,495)10.23 
Outstanding at December 31632,468 10.23 1.91
Vested or expected to vest at December 31632,468 10.23 1.91
Exercisable at December 31632,468 $10.23 1.91
(1) Represents additional payout of existing stock option grants.
Restricted Stock Units

Restricted stock units generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2025, 2024, and 2023 was $16.43, $16.74, and $15.70, respectively.  The total fair value of restricted stock units that vested during 2025, 2024, and 2023 was $70 million, $62 million, and $64 million, respectively.  The tax benefit from restricted stock units that vested in 2025 was $8 million.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2025, $108 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.60 years.

The following table summarizes restricted stock unit activity for 2025:
Number of
Restricted Stock Units		Weighted Average Grant-
Date Fair Value
Nonvested at January 19,423,582 $15.52 
Granted6,252,871 16.43 
Vested(4,744,176)14.66 
Forfeited(254,623)16.21 
Nonvested at December 3110,677,654 $16.42 

Performance Shares

Performance shares generally vest three years after the grant date.  Following vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period (“TSR”) or an internal PG&E Corporation metric (subject in some instances to a multiplier based on TSR).  Dividend equivalents, if any, are paid in cash based on the amount of common stock to which the recipients are entitled.

Compensation expense attributable to performance shares is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the TSR-based awards or the grant-date market value of PG&E Corporation common stock for awards based on internal metrics.  The weighted average grant-date fair value for performance shares granted during 2025, 2024, and 2023 was $15.10, $16.94, and $13.39 respectively.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2025, $39 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.14 years.

The following table summarizes activity for performance shares in 2025:
Number of
Performance Shares		Weighted Average Grant-
Date Fair Value
Nonvested at January 17,180,206 $15.52 
Granted2,445,690 15.10 
Vested(2,831,269)11.21 
Forfeited
(332,132)16.39 
Nonvested at December 316,462,495 $16.40 
v3.25.4
PREFERRED STOCK
 12 Months Ended
Dec. 31, 2025
Preferred Stock [Abstract]  
PREFERRED STOCK PREFERRED STOCK
PG&E Corporation

PG&E Corporation has authorized 400 million shares of preferred stock.

On December 5, 2024, PG&E Corporation issued 32,200,000 shares of 6.000% Series A Mandatory Convertible Preferred Stock, at $50.00 per share, for cash proceeds of approximately $1.6 billion. The proceeds from this issuance are intended to be used for general corporate purposes, which may include, among other things, to fund its five-year capital investment plan.
Each share of the Mandatory Convertible Preferred Stock will automatically convert on December 1, 2027. The number of shares of common stock issuable on conversion of Mandatory Convertible Preferred Stock will not be more than 2.4331 shares of common stock and not less than 1.9465 shares of common stock.

Other than during a Fundamental Change Conversion Period (as defined in the PG&E Corporation Preferred Stock Certificate of Designation), at any time prior to December 1, 2027, holders of Mandatory Convertible Preferred Stock have the option to elect to convert their shares of the Mandatory Convertible Preferred Stock, in whole or in part (but in no event in increments of less than one share of the Mandatory Convertible Preferred Stock), into shares of common stock at the Minimum Conversion Rate of 1.9465 shares of common stock per share of Mandatory Convertible Preferred Stock, subject to adjustment as described in the Preferred Stock Preliminary Prospectus Supplement.

Utility

The Utility has authorized 75 million shares of first preferred stock, with a par value of $25 per share, and 10 million shares of $100 first preferred stock, with a par value of $100 per share.  At December 31, 2025 and 2024, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. No shares of $100 first preferred stock are outstanding.

Dividends

PG&E Corporation

All shares of the Mandatory Convertible Preferred Stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of the Mandatory Convertible Preferred Stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.

Dividends on the Mandatory Convertible Preferred Stock are cumulative. The Mandatory Convertible Preferred Stock ranks senior to PG&E Corporation’s common stock with respect to the payment of dividends. Accordingly, unless accumulated dividends have been paid on all of the Mandatory Convertible Preferred Stock through the most recently completed dividend period, no dividends may be declared or paid on PG&E Corporation’s common stock and PG&E Corporation will not be permitted to repurchase any of its common stock, subject to limited exceptions.

Utility

At December 31, 2025, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2025, annual dividends on the Utility’s redeemable preferred stock ranged from $1.09 to $1.25 per share.

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  
The following table summarizes the dividends on preferred stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation mandatory convertible preferred stock$0.7167 $23 December 12, 2024February 14, 2025February 27, 2025
0.75 24 February 20, 2025May 15, 2025May 29, 2025
0.75 24 May 22, 2025August 15, 2025August 28, 2025
0.75 24 September 18, 2025November 14, 2025December 1, 2025
0.75 24 December 11, 2025February 13, 2026March 1, 2026
Utility preferred stockvaries by series3.5 November 29, 2024January 31, 2025February 15, 2025
varies by series3.5 February 20, 2025April 30, 2025May 15, 2025
varies by series3.5 May 22, 2025July 31, 2025August 15, 2025
varies by series3.5 September 18, 2025October 31, 2025November 15, 2025
varies by series3.5 December 11, 2025January 30, 2026February 15, 2026

For more information on dividend policy, see Note 6 above.
v3.25.4
EARNINGS PER SHARE
 12 Months Ended
Dec. 31, 2025
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 by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2025, 2024, and 2023.
 Year Ended December 31,
(in millions, except per share amounts)202520242023
Income available for common shareholders$2,593 $2,475 $2,242 
Weighted average common shares outstanding, basic (1)
2,197 2,141 2,064 
Add incremental shares from assumed conversions:
Employee share-based compensation
5 6 6 
Equity Units— — 68 
Weighted average common shares outstanding, diluted2,202 2,147 2,138 
Total earnings per common share, diluted$1.18 $1.15 $1.05 
(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 number of options and securities that were antidilutive. For the year ended December 31, 2025, the calculation of outstanding common shares on a diluted basis excluded the impacts of the Mandatory Convertible Preferred Stock (see Note 7 above), which were antidilutive. In addition, as a result of an irrevocable election made on December 8, 2023 to fix the settlement method to Combination Settlement, the Convertible Notes (as defined in Note 4) did not have a material impact on the calculation of diluted EPS.
v3.25.4
INCOME TAXES
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
INCOME TAXES INCOME TAXES
PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense or tax carryforwards.
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.

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

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

The significant components of income tax expense (benefit) were as follows:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)202520242023202520242023
Current:      
Federal$(1)$2 $(1)$(1)$2 $(1)
State50 (78)— 89 (78)— 
Deferred:
Federal(225)(137)(1,047)(171)(72)(981)
State(102)15 (507)(109)45 (477)
Federal tax credits(2)(2)(2)(2)(2)(2)
Total income tax benefit
$(280)$(200)$(1,557)$(194)$(105)$(1,461)
The following tables describe net deferred income tax assets and liabilities:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)2025202420252024
Deferred income tax assets:    
Tax carryforwards$9,752 $9,429 $9,199 $8,955 
Compensation211 171 127 86 
GHG allowances457 471 457 471 
Wildfire-related claims (1)
227 295 227 295 
Operating lease liability
111 78 111 78 
Transmission tower wireless license251 251 251 251 
Bad debt137 127 137 127 
Other (2)
127 140 156 137 
Total deferred income tax assets$11,273 $10,962 $10,665 $10,400 
Deferred income tax liabilities:    
Property-related basis difference12,357 11,021 12,344 11,009 
Regulatory balancing accounts487 878 487 878 
Income tax regulatory asset (3)
1,723 1,335 1,723 1,335 
Debt financing costs353 390 353 390 
Operating lease ROU asset111 78 111 78 
Environmental reserve288 248 288 248 
Other (4)
89 94 91 94 
Total deferred income tax liabilities$15,408 $14,044 $15,397 $14,032 
Total net deferred income tax liabilities$4,135 $3,082 $4,732 $3,632 
(1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in the Utility’s service area over the past several years.
(2) Amounts include benefits, state taxes, and customer advances for construction.
(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax.
(4) Amounts primarily include property taxes.

The following tables reconcile income tax expense at the federal statutory rate to the income tax provision:
 PG&E Corporation
 Year Ended December 31,
(in millions)202520242023
Federal statutory income tax rate21.0 %$486 21.0 %$478 21.0 %$144 
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(1.8)(41)(2.0)(45)(57.9)(397)
Effect of regulatory treatment of fixed asset differences (2)
(34.2)(790)(28.9)(657)(62.4)(428)
Changes in valuation allowance
0.8 18 (0.9)(20)0.7 5 
Nontaxable or nondeductible items
2.2 51 0.8 19 0.2 1 
Tax credits(1.1)(26)(1.0)(22)(3.4)(24)
Changes in unrecognized tax benefits0.1 3 2.1 46 0.2 2 
Fire Victim Trust (3)
— — — — (126.9)(869)
Other, net0.9 19 0.1 1 1.3 9 
Effective tax rate(12.1)%$(280)(8.8)%$(200)(227.2)%$(1,557)
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.

 Utility
 Year Ended December 31,
(in millions)202520242023
Federal statutory income tax rate21.0 %$606 21.0 %$547 21.0 %$228 
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(0.6)(16)(0.8)(22)(34.4)(373)
Effect of regulatory treatment of fixed asset differences (2)
(27.4)(790)(25.2)(657)(39.5)(428)
Changes in valuation allowance— — — — 0.1 1 
Nontaxable or nondeductible items1.1 30 0.4 12 — — 
Tax credits(0.9)(26)(0.9)(22)(2.2)(24)
Changes in unrecognized tax benefits
0.1 3 1.9 49 0.2 2 
Fire Victim Trust (3)
— — — — (80.2)(869)
Other, net— (1)(0.4)(12)0.2 2 
Effective tax rate(6.7)%$(194)(4.0)%$(105)(134.8)%$(1,461)
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.

Unrecognized Tax Benefits

The following table reconciles the changes in unrecognized tax benefits:
 PG&E CorporationUtility
(in millions)202520242023202520242023
Balance at beginning of year$454 $616 $570 $454 $616 $570 
Additions for tax position taken during a prior year5 — 1 5 — 1 
Reductions for tax position taken during a prior year(7)(257)— (7)(257)— 
Additions for tax position taken during the current year665 95 45 665 95 45 
Balance at end of year
$1,117 $454 $616 $1,117 $454 $616 

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2025 for PG&E Corporation and the Utility was $102 million.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months based on tax audit progress.

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2025, 2024, and 2023, these amounts were immaterial.
Tax Audits

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The 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. On June 4, 2024, 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 decreased its Income tax benefit by $70 million related to state and federal income taxes in 2024. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
(in millions)December 31, 2025Expiration
Year
Federal:  
Net operating loss carryforward - Pre-2018$3,307 2031 - 2036
Net operating loss carryforward - Post-201734,957 N/A
Tax credit carryforward226 Various
State:
Net operating loss carryforward$34,143 2039 - 2041
Tax credit carryforward167 Various

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards.
v3.25.4
DERIVATIVES
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
DERIVATIVES DERIVATIVES
Use of Derivative Instruments

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

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

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

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

The volumes of the Utility’s outstanding derivatives were as follows:
  Contract Volume at
Underlying ProductInstrumentsDecember 31, 2025December 31, 2024
Natural Gas (1) (MMBtus (2))
Forwards, futures, and swaps232,825,834 179,257,247 
 Options48,215,000 37,717,500 
Electricity (MWh)Forwards, futures, and swaps7,196,942 8,576,078 
Options1,650,800 1,663,200 
 
Congestion Revenue Rights (3)
93,712,644 123,040,895 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal 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 

As of December 31, 2024, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal Derivative
Balance
Current assets – other$186 $(16)$170 
Noncurrent assets – other233 — 233 
Current liabilities – other(152)16 (136)
Noncurrent liabilities – other(167)— (167)
Total commodity risk$100 $— $100 

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

Some of the Utility’s 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. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of December 31, 2025, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.
v3.25.4
FAIR VALUE MEASUREMENTS
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments
$634 $— $— $— $634 
Fixed-income securities— — — — — 
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 10)
     
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 10)
     
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 Measurements
 
At December 31, 2024
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$826 $— $— $— $826 
Pacific Energy Risk Solutions, LLC
  Short-term investments905 — — — 905 
Total Pacific Energy Risk Solutions, LLC905 — — — 905 
Nuclear decommissioning trusts
Short-term investments53 — — — 53 
Global equity securities2,228 — — — 2,228 
Fixed-income securities1,250 1,027 — — 2,277 
Assets measured at NAV— — — — 22 
Total nuclear decommissioning trusts (2)
3,531 1,027 — — 4,580 
Customer credit trust
Short-term investments1 — — — 1 
Global equity securities186 — — — 186 
Fixed-income securities46 144 — — 190 
Total customer credit trust
233 144 — — 377 
Price risk management instruments (Note 10)
    
Electricity— 26 383 (6)403 
Gas— 10 — (10)— 
Total price risk management instruments— 36 383 (16)403 
Rabbi trusts    
Short-term investments107 — — — 107 
Global equity securities6 — — — 6 
Life insurance contracts— 66 — — 66 
Total rabbi trusts113 66 — — 179 
Long-term disability trust    
Short-term investments4 — — — 4 
Assets measured at NAV— — — — 130 
Total long-term disability trust4 — — — 134 
TOTAL ASSETS$5,612 $1,273 $383 $(16)$7,404 
Liabilities:    
Price risk management instruments (Note 10)
    
Electricity$— $37 $248 $(6)$279 
Gas— 34 — (10)24 
TOTAL LIABILITIES$— $71 $248 $(16)$303 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.
Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the years ended December 31, 2025 or 2024.
Trust Assets

Assets Measured at Fair Value

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

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

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

Assets Measured at NAV Using Practical Expedient

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

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 10 above.
 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.

 Fair Value
(in millions)		   
At December 31, 2024Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$366 $121 Market approachCRR auction prices
$ (951) - 50,044 / 2
Power purchase agreements$17 $127 Discounted cash flowForward prices
$ 0 - 126 / 47
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2025 and 2024:
 Price Risk Management Instruments
(in millions)20252024
Asset balance as of January 1$127 $191 
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)
26 (64)
Asset balance as of December 31$153 $127 
(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 December 31, 2025 and December 31, 2024, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
 
At December 31, 2025
At December 31, 2024
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount
Level 2 Fair Value
Debt (Note 4)    
PG&E Corporation (1)
$5,360 $5,697 $5,358 $5,829 
Utility38,145 35,565 37,812 34,532 
(1) As of December 31, 2025, 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 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 
As of December 31, 2024    
Nuclear decommissioning trusts    
Short-term investments$54 $— $(1)$53 
Global equity securities353 1,907 (10)2,250 
Fixed-income securities2,341 20 (84)2,277 
Total (1)
$2,748 $1,927 $(95)$4,580 
(1) Represents amounts before deducting $881 million and $747 million as of December 31, 2025 and December 31, 2024, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2025
Less than 1 year$95 
1–5 years822 
5–10 years564 
More than 10 years1,077 
Total maturities of fixed-income securities$2,558 
The following table provides a summary of activity for the fixed-income and equity securities:
(in millions)202520242023
Proceeds from sales and maturities of nuclear decommissioning trust investments$1,952 $1,980 $2,235 
Gross realized gains on securities213 255 80 
Gross realized losses on securities(25)(63)(74)
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 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 
As of December 31, 2024    
Customer credit trust    
Short-term investments$1 $— $— $1 
Global equity securities161 28 (3)186 
Fixed-income securities193 1 (4)190 
Total
$355 $29 $(7)$377 
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2025
Less than 1 year$290 
1–5 years107 
5–10 years49 
More than 10 years247 
Total maturities of fixed-income securities$693 
The following table provides a summary of activity for the fixed-income and equity securities:
(in millions)202520242023
Proceeds from sales and maturities of customer credit trust investments$435 $398 $556 
Gross realized gains on securities131 10$23 
Gross realized losses on securities
(20)(8)$(19)
v3.25.4
EMPLOYEE BENEFIT PLANS
 12 Months Ended
Dec. 31, 2025
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]  
EMPLOYEE BENEFIT PLANS EMPLOYEE BENEFIT PLANS
Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

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

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

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2025 and 2024:

Pension Plan
(in millions)20252024
Change in plan assets:
Fair value of plan assets at beginning of year$16,767 $17,211 
Actual return on plan assets1,779 218 
Company contributions337 337 
Benefits and expenses paid(1,020)(999)
Fair value of plan assets at end of year$17,863 $16,767 
Change in benefit obligation:
Benefit obligation at beginning of year$17,585 $17,697 
Service cost for benefits earned424 396 
Interest cost1,007 916 
Actuarial loss (gain) (1)
427 (424)
Benefits and expenses paid(1,020)(1,000)
Benefit obligation at end of year (2)
$18,423 $17,585 
Funded Status:
Current liability$(10)$(10)
Noncurrent liability(550)(808)
Net liability at end of year
$(560)$(818)
(1) The actuarial loss for the year ended December 31, 2025 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in demographic assumptions; the actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions.
(2) PG&E Corporation’s accumulated benefit obligation was $16.5 billion and $15.8 billion at December 31, 2025 and 2024, respectively.
Postretirement Benefits Other than Pensions
(in millions)20252024
Change in plan assets:
Fair value of plan assets at beginning of year$2,471 $2,499 
Actual return on plan assets200 74 
Company contributions7 5 
Plan participant contribution91 84 
Benefits and expenses paid(196)(191)
Fair value of plan assets at end of year$2,573 $2,471 
Change in benefit obligation:
Benefit obligation at beginning of year$1,279 $1,377 
Service cost for benefits earned38 41 
Interest cost73 71 
Actuarial loss (gain) (1)
125 (123)
Benefits and expenses paid(182)(174)
Federal subsidy on benefits paid4 3 
Plan participant contributions91 84 
Benefit obligation at end of year$1,428 $1,279 
Funded Status: (2)
Noncurrent asset$1,144 $1,192 
Noncurrent liability— — 
Net asset at end of year$1,144 $1,192 
(1) The actuarial loss for the year ended December 31, 2025 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations and unfavorable changes in claims cost, medical trends, and demographic assumptions. The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets.
(2) At December 31, 2025 and 2024, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $274 million and $322 million as of December 31, 2025, and $261 million and $296 million as of December 31, 2024, respectively.

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

Components of Net Periodic Benefit Cost

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

Pension Plan
(in millions)202520242023
Service cost for benefits earned (1)
$424 $396 $379 
Interest cost1,007 916 913 
Expected return on plan assets(1,053)(1,014)(981)
Amortization of prior service cost(3)(3)(4)
Amortization of net actuarial loss2 1 1 
Net periodic benefit cost377 296 308 
Less: transfer to regulatory account (2)
(40)39 25 
Total expense recognized$337 $335 $333 
(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.
(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions
(in millions)202520242023
Service cost for benefits earned (1)
$38 $41 $38 
Interest cost73 71 73 
Expected return on plan assets(150)(139)(132)
Amortization of prior service cost3 3 3 
Amortization of net actuarial gain(23)(23)(19)
Net periodic benefit cost$(59)$(47)$(37)
(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.

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

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

Components of Accumulated Other Comprehensive Income

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

The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
 Pension PlanPBOP Plans
 December 31,December 31,
 202520242023202520242023
Discount rate5.58 %5.76 %5.21 %
5.51 - 5.60%
5.71 - 5.76%
5.18 - 5.22%
Rate of future compensation increases4.80 %4.80 %3.80 %N/AN/AN/A
Expected return on plan assets7.00 %6.40 %6.00 %
4.30 - 7.20%
3.90 - 7.20%
3.70 - 7.00%
Interest crediting rate for cash balance plan4.23 %4.41 %3.86 %N/AN/AN/A

The assumed health care cost trend rate as of December 31, 2025 was 7.00%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2036 and beyond.

Expected rates of return on plan assets were developed by estimating future asset class returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were projected based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 7.0% compares to a ten-year actual return of 5.7%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 831 Aa-grade non-callable bonds at December 31, 2025.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

Investment Policies and Strategies

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

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

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the allocation between fixed income and equity of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non-U.S. dollar exposure of global equity investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
 Pension PlanPBOP Plans
 202620252024202620252024
Global equity securities28 %26 %26 %14 %30 %29 %
Absolute return1 1 1 — — — 
Real assets6 8 8 3 3 3 
Fixed-income securities65 65 65 83 67 68 
Total100 %100 %100 %100 %100 %100 %

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

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2025 and 2024.
 Fair Value Measurements
 At December 31,
 20252024
(in millions)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Pension Plan:        
Short-term investments$452 $30 $— $482 $126 $47 $— $173 
Global equity securities1,445 — — 1,445 1,310 — — 1,310 
Real assets2 — — 2 437 — — 437 
Fixed-income securities1,990 6,880 12 8,882 2,180 6,367 16 8,563 
Assets measured at NAV— — — 7,052 — — — 6,284 
Total$3,889 $6,910 $12 $17,863 $4,053 $6,414 $16 $16,767 
PBOP Plans:        
Short-term investments$546 $— $— $546 $27 $— $— $27 
Global equity securities2 — — 2 60 — — 60 
Real assets— — — — 20 — — 20 
Fixed-income securities518 561 — 1,079 431 751 1 1,183 
Assets measured at NAV— — — 946 — — — 1,181 
Total$1,066 $561 $— $2,573 $538 $751 $1 $2,471 
Total plan assets at fair value   $20,436    $19,238 

Valuation Techniques

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

Short-Term Investments

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

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

Real Assets

The real asset category includes portfolios of private real estate funds. These funds are measured at NAV as a practical expedient.

Fixed-Income Securities

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

Assets Measured at NAV Using Practical Expedient

Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges, fixed-income securities that are composed primarily of U.S. government securities, credit securities and asset-backed securities, and real assets and absolute return investments that are held to diversify the trust’s holdings in equity and fixed-income securities.

Transfers Between Levels

No material transfers between levels occurred in the years ended December 31, 2025 or 2024.
Level 3 Reconciliation

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2025 and 2024:
(in millions)
For the year ended December 31, 2025
Fixed-Income
Balance at beginning of year$16 
Actual return on plan assets:
Relating to assets still held at the reporting date7 
Relating to assets sold during the period(7)
Purchases, issuances, sales, and settlements:
Purchases6 
Settlements(10)
Balance at end of year$12 
  
(in millions)
For the year ended December 31, 2024
Fixed-Income
Balance at beginning of year$13 
Actual return on plan assets:
Relating to assets still held at the reporting date9 
Relating to assets sold during the period(9)
Purchases, issuances, sales, and settlements:
Purchases14 
Settlements(11)
Balance at end of year$16 

There were no material transfers out of Level 3 in 2025 or 2024.

Cash Flow Information

Employer Contributions

PG&E Corporation and the Utility contributed $337 million to the pension benefit plans, $31 million to the long-term disability trusts, and $7 million to the other postretirement benefit plans in 2025.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. The Utility’s pension benefits met all funding requirements under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million to the qualified pension plan in 2026. PG&E Corporation and the Utility plan to contribute $31 million to the long-term disability trusts in 2026, as authorized in the 2023 GRC.

Benefits Payments and Receipts

As of December 31, 2025, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
(in millions)Pension
Plan		PBOP
Plans		Federal
Subsidy
2026993 84 (1)
20271,082 86 (1)
20281,110 90 (1)
20291,136 93 (1)
20301,161 96 (1)
2031-20356,159 523 (6)
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and the Utility for the years presented above.

Retirement Savings Plan

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the IRC. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan and provides for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $194 million, $175 million, and $158 million in 2025, 2024, and 2023, respectively. PG&E Corporation’s default matching contributions under its 401(k) plan are in cash.

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
v3.25.4
RELATED PARTY AGREEMENTS AND TRANSACTIONS
 12 Months Ended
Dec. 31, 2025
Related Party Transactions [Abstract]  
RELATED PARTY AGREEMENTS AND TRANSACTIONS RELATED PARTY AGREEMENTS AND TRANSACTIONS
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) plus five percent of direct labor costs or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are priced at the lower of fully loaded cost or fair market value. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
v3.25.4
WILDFIRE-RELATED CONTINGENCIES
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025.
Payments (in millions)
2019 Kincade Fire
$1,287 
2021 Dixie Fire1,908 
2022 Mosquito Fire107 
Total at December 31, 2025
$3,302 
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

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

As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 3,014 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024, the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

On October 11, 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 $1.225 billion as of December 31, 2024 (before available insurance). In each of the first and second quarters of 2025, PG&E Corporation and the Utility recorded additional charges of $50 million, for an aggregate liability of $1.325 billion (before available insurance).

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 or any punitive damages.

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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$267 
Accrued Losses100 
Payments(329)
Balance at December 31, 2025
$38 

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 December 31, 2025, the Utility received $111 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 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 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 or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 189 complaints on behalf of at least 9,034 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. As of February 4, 2026, the writ remains pending with the Court of Appeal.

On February 7, 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 June 18, 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 $1.925 billion as of December 31, 2024 (before available recoveries). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2025 of $225 million, of which $25 million was recorded in the fourth quarter, for an aggregate liability of $2.150 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.150 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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$567 
Accrued Losses225 
Payments(549)
Balance at December 31, 2025
$243 

As of December 31, 2025, 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 $1.150 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025. 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 December 31, 2025, 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 $535 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 February 4, 2026, PG&E Corporation and the Utility are aware of approximately 35 complaints on behalf of at least 2,939 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and a group of six public entities have each filed complaints. 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 settlement agreements with five public entities. The court has set individual claimant bellwether trial dates for April 13, 2026.

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 $100 million as of December 31, 2024 (before available recoveries). During 2025, PG&E Corporation and the Utility recorded additional charges of $250 million, of which $100 million was recorded in the fourth quarter, for an aggregate liability of $350 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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$82 
Accrued Losses250 
Payments(89)
Balance at December 31, 2025
$243 

As of December 31, 2025, the Utility recorded an insurance receivable of $363 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of December 31, 2025, 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 December 31, 2025 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $363 
FERC TO rates
97 7 
WEMA
535 54 
Wildfire Fund
1,150 — 
Probable recoveries at December 31, 2025 (1)
$2,303 $424 
(1) Includes legal costs of $148 million and $73 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2025.

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 December 31, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $521 million and $363 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 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, 2024:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2024
$27 $90 $117 
Accrued insurance recoveries
(6)273 267 
Reimbursements
(20)(82)(102)
Balance at December 31, 2025
$1 $281 $282 
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.

FERC TO Rates

The Utility recognizes income and reduces its regulatory liability for potential refund 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 transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2025, the Utility recorded reductions of $97 million and $7 million, 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 December 31, 2025, 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 $535 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 December 31, 2025 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 $4.7 billion for 2025. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2025 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.

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 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 December 31, 2025, PG&E Corporation and the Utility recorded $295 million and $4 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, 2024:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2024
$756 
Accrued Wildfire Fund recoveries225 
Claims paid by Wildfire Fund(682)
Balance at December 31, 2025
$299 

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. A hearing on the motion for preliminary approval in the District Court is scheduled for February 26, 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.
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, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. Such claims could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation 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 prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.
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.
CPUC 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.
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 $151 million and $74 million as of December 31, 2025 and 2024, respectively. These amounts were included in Other current liabilities on the 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 14 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 Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)December 31, 2025December 31, 2024
Topock natural gas compressor station$315 $294 
Hinkley natural gas compressor station99 97 
Former MGP sites owned by the Utility or third parties (1)
715 782 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
71 76 
Fossil fuel-fired generation facilities and sites (3)
17 18 
Total environmental remediation liability$1,217 $1,267 
(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 EPA 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 December 31, 2025, 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 December 31, 2025, the Utility expected to recover $1.0 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 December 31, 2025
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$315 $518 Available
Hinkley natural gas compressor station (2)
99 221 Unavailable
Former MGP sites owned by the Utility or third parties (3)
715 1,292 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
71 146 Available
Fossil fuel-fired generation facilities and sites (5)
17 32 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, a mutual insurer owned by utilities with nuclear facilities, and European Mutual Association for Nuclear Insurance (“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 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 $43 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $500 million for DCPP. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.
The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $500 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, covering liabilities in excess of the $53 million in liability insurance.
Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2025:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		Natural
Gas
Other (1)
Total
2026$1,937 $1,058 $544 $278 $3,817 
20271,921 1,035 193 134 3,283 
20281,903 989 106 47 3,045 
20291,858 905 98 6 2,867 
20301,852 510 42 2 2,406 
Thereafter12,828 4,315 34 5 17,182 
Total purchase commitments$22,299 $8,812 $1,017 $472 $32,600 
(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

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

Renewable Energy Power Purchase Agreements

In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  These renewable energy contracts expire at various dates between 2026 and 2047.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2026 and 2044.

Other Power Purchase Agreements

The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2025, QF contracts in operation expire at various dates between 2026 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.0 billion in 2025, $2.1 billion in 2024, and $2.4 billion in 2023.
Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers, and to fuel its owned-generation facilities along with a facility associated with a third party tolling agreement.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the United States Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2026 and 2035.  In addition, the Utility has contracted for natural gas storage services in Northern California and Canada to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, were $1.0 billion in 2025, $0.8 billion in 2024, and $2.5 billion in 2023.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2026 and 2030 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

Payments for nuclear fuel were $134 million in 2025, $294 million in 2024, and $180 million in 2023.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities leases and land leases which expire at various dates between 2026 and 2054, as well as other multi-year agreements.  At December 31, 2025, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2026$82 
202751 
202841 
202939 
203013 
Thereafter65 
Total minimum payments$291 

Payments for other commitments were $63 million in 2025, $105 million in 2024, and $106 million in 2023.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

In addition to the commitments in the table above, if the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution to the customer credit trust of up to $775 million in 2040. The Utility also will share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025.
Payments (in millions)
2019 Kincade Fire
$1,287 
2021 Dixie Fire1,908 
2022 Mosquito Fire107 
Total at December 31, 2025
$3,302 
2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m. Pacific Time, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service area of the Utility. According to a Cal Fire incident update dated March 3, 2020, 3:35 p.m. Pacific Time, the 2019 Kincade fire consumed 77,758 acres and resulted in no fatalities, four first responder injuries, 374 structures destroyed, and 60 structures damaged. In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

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

As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 135 complaints on behalf of at least 3,014 plaintiffs related to the 2019 Kincade fire. The plaintiffs filed master complaints on July 16, 2021; PG&E Corporation’s and the Utility’s response was filed on August 16, 2021; and PG&E Corporation and the Utility filed a demurrer with respect to the plaintiffs’ inverse condemnation claims. On December 10, 2021, the court overruled the demurrer. On July 20, 2022, PG&E Corporation and the Utility filed a motion for summary adjudication on individual plaintiffs’ claims for punitive damages. On July 14, 2024, the court vacated the bellwether trial date that had been scheduled for August 26, 2024, as well as the hearing on the motion for summary adjudication.

On October 11, 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 $1.225 billion as of December 31, 2024 (before available insurance). In each of the first and second quarters of 2025, PG&E Corporation and the Utility recorded additional charges of $50 million, for an aggregate liability of $1.325 billion (before available insurance).

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 or any punitive damages.

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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$267 
Accrued Losses100 
Payments(329)
Balance at December 31, 2025
$38 

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 December 31, 2025, the Utility received $111 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 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 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 or the FERC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable, the Utility would not be able to recover costs through FERC TO rates, or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of February 4, 2026, PG&E Corporation and the Utility are aware of approximately 189 complaints on behalf of at least 9,034 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. As of February 4, 2026, the writ remains pending with the Court of Appeal.

On February 7, 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 June 18, 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 $1.925 billion as of December 31, 2024 (before available recoveries). Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during 2025 of $225 million, of which $25 million was recorded in the fourth quarter, for an aggregate liability of $2.150 billion (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.150 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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$567 
Accrued Losses225 
Payments(549)
Balance at December 31, 2025
$243 

As of December 31, 2025, 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 $1.150 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $851 million as of December 31, 2025. 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 December 31, 2025, 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 $535 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 February 4, 2026, PG&E Corporation and the Utility are aware of approximately 35 complaints on behalf of at least 2,939 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and a group of six public entities have each filed complaints. 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 settlement agreements with five public entities. The court has set individual claimant bellwether trial dates for April 13, 2026.

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 $100 million as of December 31, 2024 (before available recoveries). During 2025, PG&E Corporation and the Utility recorded additional charges of $250 million, of which $100 million was recorded in the fourth quarter, for an aggregate liability of $350 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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$82 
Accrued Losses250 
Payments(89)
Balance at December 31, 2025
$243 

As of December 31, 2025, the Utility recorded an insurance receivable of $363 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees. As of December 31, 2025, 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 December 31, 2025 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $363 
FERC TO rates
97 7 
WEMA
535 54 
Wildfire Fund
1,150 — 
Probable recoveries at December 31, 2025 (1)
$2,303 $424 
(1) Includes legal costs of $148 million and $73 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2025.

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 December 31, 2025, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $521 million and $363 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 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, 2024:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2024
$27 $90 $117 
Accrued insurance recoveries
(6)273 267 
Reimbursements
(20)(82)(102)
Balance at December 31, 2025
$1 $281 $282 
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.

FERC TO Rates

The Utility recognizes income and reduces its regulatory liability for potential refund 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 transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on information currently available to the Utility regarding the 2021 Dixie fire and the 2022 Mosquito fire, as of December 31, 2025, the Utility recorded reductions of $97 million and $7 million, 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 December 31, 2025, 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 $535 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 December 31, 2025 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 $4.7 billion for 2025. This disallowance cap is based on the equity portion of the Utility’s forecasted weighted-average 2025 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.

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 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 December 31, 2025, PG&E Corporation and the Utility recorded $295 million and $4 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, 2024:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2024
$756 
Accrued Wildfire Fund recoveries225 
Claims paid by Wildfire Fund(682)
Balance at December 31, 2025
$299 

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. A hearing on the motion for preliminary approval in the District Court is scheduled for February 26, 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.
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, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. Such claims could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation 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 prosecute omnibus objections with respect to certain of the Subordinated Claims and act under the procedures approved by the Bankruptcy Court to resolve the Subordinated Claims.
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.
CPUC 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.
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 $151 million and $74 million as of December 31, 2025 and 2024, respectively. These amounts were included in Other current liabilities on the 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 14 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 Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)December 31, 2025December 31, 2024
Topock natural gas compressor station$315 $294 
Hinkley natural gas compressor station99 97 
Former MGP sites owned by the Utility or third parties (1)
715 782 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
71 76 
Fossil fuel-fired generation facilities and sites (3)
17 18 
Total environmental remediation liability$1,217 $1,267 
(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 EPA 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 December 31, 2025, 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 December 31, 2025, the Utility expected to recover $1.0 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 December 31, 2025
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$315 $518 Available
Hinkley natural gas compressor station (2)
99 221 Unavailable
Former MGP sites owned by the Utility or third parties (3)
715 1,292 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
71 146 Available
Fossil fuel-fired generation facilities and sites (5)
17 32 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, a mutual insurer owned by utilities with nuclear facilities, and European Mutual Association for Nuclear Insurance (“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 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 $43 million. 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at DCPP, and that occur during the transportation of material to and from DCPP are limited to approximately $16.3 billion. The Utility purchases the maximum available public liability insurance of $500 million for DCPP. The balance of the $16.3 billion of liability protection is provided under a loss-sharing program among nuclear reactor owners. The Utility may be assessed up to $332 million per nuclear incident under this loss sharing program, with payments in each year limited to a maximum of $49 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.
The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $500 million per incident. In addition, the Utility has approximately $53 million of liability insurance for the Humboldt Bay independent spent fuel storage installation and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for the Humboldt Bay independent spent fuel storage installation, covering liabilities in excess of the $53 million in liability insurance.
Purchase Commitments

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2025:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		Natural
Gas
Other (1)
Total
2026$1,937 $1,058 $544 $278 $3,817 
20271,921 1,035 193 134 3,283 
20281,903 989 106 47 3,045 
20291,858 905 98 6 2,867 
20301,852 510 42 2 2,406 
Thereafter12,828 4,315 34 5 17,182 
Total purchase commitments$22,299 $8,812 $1,017 $472 $32,600 
(1) Includes other power purchase agreements and nuclear fuel agreements.

Third-Party Power Purchase Agreements

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

Renewable Energy Power Purchase Agreements

In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  These renewable energy contracts expire at various dates between 2026 and 2047.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase agreements for conventional generation resources, which include a tolling agreement and RA agreements.  The Utility’s obligations under a portion of these agreements are contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. These power purchase agreements expire at various dates between 2026 and 2044.

Other Power Purchase Agreements

The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. As of December 31, 2025, QF contracts in operation expire at various dates between 2026 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

The net costs incurred for all power purchases and electric capacity were $2.0 billion in 2025, $2.1 billion in 2024, and $2.4 billion in 2023.
Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers, and to fuel its owned-generation facilities along with a facility associated with a third party tolling agreement.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the United States Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2026 and 2035.  In addition, the Utility has contracted for natural gas storage services in Northern California and Canada to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, were $1.0 billion in 2025, $0.8 billion in 2024, and $2.5 billion in 2023.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2026 and 2030 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

Payments for nuclear fuel were $134 million in 2025, $294 million in 2024, and $180 million in 2023.

Other Commitments

PG&E Corporation and the Utility have other commitments primarily related to office facilities leases and land leases which expire at various dates between 2026 and 2054, as well as other multi-year agreements.  At December 31, 2025, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2026$82 
202751 
202841 
202939 
203013 
Thereafter65 
Total minimum payments$291 

Payments for other commitments were $63 million in 2025, $105 million in 2024, and $106 million in 2023.  Certain office facility leases contain escalation clauses requiring annual increases in rent.  The rents may increase by a fixed amount each year, a percentage of the base rent, or the consumer price index.  There are options to extend these leases for one to five years.

In addition to the commitments in the table above, if the CPUC determines that it is needed, the Utility will make a supplemental shareholder contribution to the customer credit trust of up to $775 million in 2040. The Utility also will share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.
v3.25.4
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT
 12 Months Ended
Dec. 31, 2025
Condensed Financial Information Disclosure [Abstract]  
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT
PG&E CORPORATION
SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”)
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
 Years Ended December 31,
(in millions, except per share amounts)202520242023
Administrative service revenue$194 $146 $154 
Operating expenses(207)(167)(165)
Interest income11 15 13 
Interest expense(315)(270)(365)
Other expense(145)(17)(21)
Equity in earnings of subsidiaries3,065 2,697 2,530 
Income Before Income Taxes2,603 2,404 2,146 
Income tax benefit(86)(94)(96)
Net Income$2,689 $2,498 $2,242 
Preferred stock dividend requirement96 23 — 
Income Available for Common Shareholders$2,593 $2,475 $2,242 
Other Comprehensive Income (Loss)   
Pension and other postretirement benefit plans obligations (net of taxes of $0, $3, and $6, at respective dates)
(3)(7)(16)
Net unrealized gain on available-for-sale securities (net of taxes of $0, $0, and $0, respectively)
— 1 — 
Total other comprehensive income (loss)(3)(6)(16)
Comprehensive Income$2,590 $2,469 $2,226 
Weighted Average Common Shares Outstanding, Basic
2,197 2,141 2,064 
Weighted Average Common Shares Outstanding, Diluted
2,202 2,147 2,138 
Net Earnings Per Common Share, Basic$1.18 $1.16 $1.09 
Net Earnings Per Common Share, Diluted$1.18 $1.15 $1.05 
PG&E CORPORATION
SCHEDULE I — CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)
CONSOLIDATED BALANCE SHEETS
 Balance at December 31,
(in millions)20252024
ASSETS  
Current Assets  
Cash and cash equivalents$360 $235 
Restricted cash and restricted cash equivalents1 1 
Advances to affiliates54 13 
Income taxes receivable39 2 
Total current assets454 251 
Other Noncurrent Assets  
Investments in subsidiaries45,110 42,829 
Other investments182 175 
Deferred income taxes682 633 
Total other noncurrent assets45,974 43,637 
TOTAL ASSETS$46,428 $43,888 
LIABILITIES AND EQUITY  
Current Liabilities  
Accounts payable – other146 36 
Income taxes payable— 1 
Other current liabilities444 420 
Total current liabilities590 457 
Noncurrent Liabilities  
Long-term debt5,622 5,612 
Other noncurrent liabilities151 141 
Total noncurrent liabilities5,773 5,753 
Shareholders’ Equity  
Mandatory convertible preferred stock1,579 1,579 
Common stock39,168 39,086 
Reinvested earnings(650)(2,966)
Accumulated other comprehensive loss(32)(21)
Total shareholders’ equity40,065 37,678 
TOTAL LIABILITIES AND EQUITY$46,428 $43,888 
PG&E CORPORATION
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PG&E CORPORATION (“PARENT”) – (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 Year ended December 31,
 202520242023
Cash Flows from Operating Activities:   
Net income $2,689 $2,498 $2,242 
Adjustments to reconcile net income to net cash provided by operating activities:   
Stock-based compensation amortization82 53 4 
Equity in earnings of subsidiaries(3,065)(2,699)(2,530)
Deferred income taxes and tax credits, net(49)(94)(116)
Current income taxes payable(33)— 9 
Other55 9 40 
Net cash used in operating activities
(321)(233)(351)
Cash Flows From Investing Activities:   
Investment in subsidiaries(1,575)(5,360)(1,290)
Dividends received from subsidiaries (1)
2,350 2,025 1,775 
Net cash provided by (used in) investing activities
775 (3,335)485 
Cash Flows From Financing Activities:   
Repayments under term loan credit facilities— (500)(2,181)
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $0, and $27 at respective dates
— — 2,123 
Proceeds from issuance of long-term debt, net of premium and
   issuance costs of $0, $4, and $0 at respective dates
— 1,496 — 
Common stock issued— 1,128 — 
Mandatory convertible preferred stock issued— 1,579 — 
Mandatory convertible preferred stock dividends paid(97)— — 
Common stock dividend paid(220)(86)— 
Other(12)(8)(6)
Net cash provided by (used in) financing activities(329)3,609 (64)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents125 41 70 
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1236 195 125 
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31$361 $236 $195 
Less: Restricted cash and restricted cash equivalents(1)(1)(3)
Cash and cash equivalents at December 31$360 $235 $192 
Supplemental disclosures of cash flow information   
Cash paid for:   
Interest, net of amounts capitalized$(306)$(215)$(309)
Supplemental disclosures of noncash investing and financing activities
Changes to PG&E Corporation common stock and treasury stock in connection
    with the share exchange with the Fire Victim Trust		$— $— $(2,517)
Common stock dividends declared but not yet paid111 55 21 
Mandatory convertible preferred stock dividends declared but not yet paid23 23 — 
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.
v3.25.4
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
 12 Months Ended
Dec. 31, 2025
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]  
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
PG&E CORPORATION

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2025, 2024, and 2023
(in millions) Additions  
DescriptionBalance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:     
2025:     
      Allowance for uncollectible accounts (1)
$418 $362 $— $372 $408 
2024: 
      Allowance for uncollectible accounts (1)
$445 $312 $— $339 $418 
2023: 
      Allowance for uncollectible accounts (1)
$166 $624 $— $345 $445 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2025, 2024, and 2023
(in millions) Additions  
DescriptionBalance at Beginning of PeriodCharged to Costs and Expenses
Charged to Other Accounts
Deductions (2)
Balance at End of Period
Valuation and qualifying accounts deducted from assets:     
2025:     
      Allowance for uncollectible accounts (1)
$418 $362 $— $372 $408 
2024:
      Allowance for uncollectible accounts (1)
$445 $312 $— $339 $418 
2023:
      Allowance for uncollectible accounts (1)
$166 $624 $— $345 $445 
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
v3.25.4
Insider Trading Arrangements
 3 Months Ended 12 Months Ended
Dec. 31, 2025
shares
Dec. 31, 2025
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
John R. Simon [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement n November 3, 2025, John R. Simon, who serves as the Executive Vice President, General Counsel and Chief Ethics and Compliance Officer of PG&E Corporation, 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 up to 50,000 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of August 1, 2026 or the execution of the sale of all 50,000 shares.  
Name John R. Simon  
Title Executive Vice President, General Counsel and Chief Ethics and Compliance Officer  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date November 3, 2025  
Expiration Date August 1, 2026  
Arrangement Duration 271 days  
Aggregate Available 50,000 50,000
Patricia K. Poppe [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement
On November 4, 2025, Patricia K. Poppe, who serves as the Chief Executive Officer of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c), for the sale of up to 62,500 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of July 31, 2026 or the execution of the sale of all 62,500 shares.
  
Name Patricia K. Poppe  
Title Chief Executive Officer  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date November 4, 2025  
Expiration Date July 31, 2026  
Arrangement Duration 269 days  
Aggregate Available 62,500 62,500
Sumeet Singh [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement
On November 13, 2025, Sumeet Singh, who serves as the Chief Executive Officer, Pacific Gas and Electric Company, and Executive Vice President, Energy Delivery of the Utility, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c), 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 Mr. Singh receives when his performance share units (“PSUs”) vest. Assuming that the PSUs vest at 100% of target, this Rule 10b5-1 plan would entail the sale of 52,450 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 May 15, 2026 or the execution of the sale of all covered shares.
  
Name Sumeet Singh  
Title Chief Executive Officer  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date November 13, 2025  
Expiration Date May 15, 2026  
Arrangement Duration 183 days  
Kerry W. Cooper [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement
On November 25, 2025, Kerry W. Cooper, who serves as the Chair of the Board of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c), for the sale of up to 10,000 shares of PG&E Corporation common stock. The trading arrangement will terminate on the earlier of December 31, 2026 or the execution of the sale of all 10,000 shares.
  
Name Kerry W. Cooper  
Title Chair of the Board  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date November 25, 2025  
Expiration Date December 31, 2026  
Arrangement Duration 401 days  
Aggregate Available 10,000 10,000
Carla J. Peterman [Member]    
Trading Arrangements, by Individual    
Material Terms of Trading Arrangement
On December 11, 2025, Carla J. Peterman, who serves as the President, PG&E Corporation, and Executive Vice President, Customer & Corporate Affairs of PG&E Corporation, adopted a Rule 10b5-1 trading arrangement that is intended to satisfy the affirmative defense conditions of Rule 10b5-1(c), 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. Peterman receives when her PSUs vest. Assuming that the PSUs vest at 100% of target, this Rule 10b5-1 plan would entail the sale of 96,095 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 November 30, 2026 or the execution of the sale of all covered shares.
  
Name Carla J. Peterman  
Title President, PG&E Corporation, and Executive Vice President, Customer & Corporate Affairs  
Rule 10b5-1 Arrangement Adopted true  
Adoption Date December 11, 2025  
Expiration Date November 30, 2026  
Arrangement Duration 354 days  
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
The objective of PG&E Corporation’s and the Utility’s cybersecurity program is to protect information assets and to mitigate against material cybersecurity threats, data and information compromise, and other risk events that could materially affect the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk, such as:

•Developing organizational understanding in managing cybersecurity risks to systems, assets, and data by regularly assessing cybersecurity internal controls and program maturity, including engaging independent third parties and participating in external regulatory compliance assessments;

•Assessing, monitoring, and imposing contractual requirements on third-party service providers for cybersecurity risks and for compliance with PG&E Corporation’s and the Utility’s policies regarding access to company networks, information security, and technology;

•Configuring and monitoring the system; employing policies, controls, and security tools, including training for employees and contractors; and limiting access and operating firewall rules as necessary and appropriate;

•Utilizing multiple government and private assessors, consultants, auditors or other third parties, as well as an internal team, for intelligence gathering, security monitoring, threat hunting, and forensic activities;

•Monitoring emerging data protection laws and regulations and implementing changes to processes designed to comply with any such laws and regulations;

•Responding to cybersecurity incidents as they are detected by containing consequences, investigating causes and impacts, and implementing mitigations;

•Maintaining and utilizing plans for resilience, mitigation, and restoring any capabilities or services that were impaired due to a cybersecurity incident;

•Maintaining cybersecurity liability insurance;

•Maintaining physical controls on a risk-informed basis, including controlling access or monitoring as appropriate; and

•Continuously improving the cybersecurity program by incorporating learning from past experiences and testing, reviewing, and enhancing the controls and capabilities discussed above, including conducting regular cybersecurity incident-response exercises.

PG&E Corporation and the Utility have identified cybersecurity as a key enterprise risk, which they manage through their enterprise risk management system.

PG&E Corporation and the Utility have not experienced any cybersecurity incidents in the last three years that have materially affected, or are reasonably likely to materially affect, the business strategy, results of operations, or financial condition of PG&E Corporation and the Utility. For more information regarding how cybersecurity threats could materially affect PG&E Corporation and the Utility, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, physical attack, or technology failure” in Item 1A. Risk Factors.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] PG&E Corporation’s and the Utility’s cybersecurity program’s strategy is to establish multiple layers of defense through logical and physical security controls so that if any particular control proves insufficient, other controls may capture and mitigate that risk,
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
PG&E Corporation’s and the Utility’s Boards of Directors, particularly their Safety and Nuclear Oversight Committees, have primary responsibility for overseeing cybersecurity risk management, including reviewing the companies’ cybersecurity policies, controls, and procedures. The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats. In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies.
Cybersecurity Risk Role of Management [Text Block] The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats. In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.
The Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions. They are responsible for assessing and managing cybersecurity risks in collaboration with the enterprise risk management team. Such persons are informed about cybersecurity vulnerabilities and incidents through daily and weekly operating reviews conducted by management and personnel closest to the work as part of the Lean operating system and as otherwise appropriate.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block] The Safety and Nuclear Oversight Committees participate in cybersecurity risk reviews to promote alignment in operations and asset management in the implementation of mitigation strategies designed to reduce the risk and impact of cybersecurity threats.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] The Executive Vice President and Chief Information Officer of PG&E Corporation and the Utility and the Senior Vice President, Chief Security Officer, and Chief Data and Analytics Officer of the Utility have collectively over 50 years of prior work experience in various roles involving information technology and cybersecurity functions.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] In the event that the Safety and Nuclear Oversight Committees identify significant exposures, including with respect to cybersecurity, they communicate such exposure to the Boards of Directors to assess PG&E Corporation’s and the Utility’s risk identification, risk management, and mitigation strategies. Management provides briefings to the Safety and Nuclear Oversight Committees at least annually, as well as briefings on important cybersecurity incidents and threats as necessary and appropriate or as requested. These briefings include describing cybersecurity threats, defenses, mitigation strategies, and risk data analytics that may impact the companies’ significant assets.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Regulation and Regulated Operations
Regulation and Regulated Operations

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

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

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

Net income (loss) is the measure that the chief operating decision maker 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 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 Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the chief operating decision maker is not regularly provided with information that is considered to be significant under ASC 280, Segment Reporting. Except for publicly available information, the information regularly provided to the chief operating decision maker 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.
Cash, Cash Equivalents, and Restricted Cash, and Restricted Cash Equivalents
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value. As of December 31, 2025 and 2024, the Utility also held $258 million and $272 million of Restricted cash and restricted cash equivalents, respectively, that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.
Revenue Recognition
Revenue Recognition

Revenue from Contracts with Customers

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

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s 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 December 31, 2025, PG&E Corporation and the Utility have 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 $402 million, $341 million, and $636 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2025, 2024, and 2023, 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 December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. As of December 31, 2024, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $260 million and $85 million, respectively.
Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 14 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 December 31, 2025, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.
Emission Allowances
Emission Allowances

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

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or for use as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Property, Plant, and Equipment
Property, Plant, and Equipment
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and allowance for funds used during construction (“AFUDC”). See “Allowance for Funds Used During Construction” below. 
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and in a pattern consistent with principal payments.  This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.77% in 2025 and 3.61% in 2024. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired asset is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.
Allowance for Funds Used During Construction
Allowance for Funds Used During Construction
AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.
Asset Retirement Obligations
PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below.

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

The total nuclear decommissioning obligation was $4.2 billion as of December 31, 2025 and $4.0 billion as of December 31, 2024 based on the cost study performed as part of the 2021 NDCTP. The Utility’s ARO assumes that DCPP operates until 2030. The ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.
Disallowance of Plant Costs
Disallowance of Plant Costs

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

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

The cost of debt and equity securities sold by the trust is determined by specific identification. Gains on the nuclear decommissioning trust investments are refundable to customers through rates, and losses are recoverable through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.
Government Assistance
Government Assistance

The Utility participated in various government assistance programs during the year ended December 31, 2025, 2024, and 2023. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

Assembly Bill 180

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as DCPP, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the year ended December 31, 2025, the Consolidated Statements of Income reflected $13 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel. During the year ended December 31, 2024, the amount recorded as a reduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel was immaterial to the Consolidated Statements of Income. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $56 million, as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

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 Consolidated Financial Statements:
(in millions)
202520242023
Long-term debt:
Beginning Balance - DWR loan outstanding
$886 $98 $312 
Proceeds received
— 980 — 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
(21)(117)(124)
Operating and maintenance expense - Loan forgiveness and other adjustments
(127)(75)(90)
Long-term debt:
Ending Balance - DWR loan outstanding$738 $886 $98 

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 years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $65 million, $265 million, and $115 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 years ended December 31, 2025, 2024, and 2023, the Consolidated Statements of Income reflected $69 million, $138 million, and $76 million, respectively, as deductions 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 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 year ended December 31, 2025 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2025 and December 31, 2024, the SPV had net accounts receivable of $3.2 billion, and outstanding borrowings of $1.8 billion and $0 million, respectively, 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 year ended December 31, 2025 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 December 31, 2025 and December 31, 2024, PG&E Recovery Funding LLC had outstanding borrowings of $3.1 billion and $3.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the 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 year ended December 31, 2025 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 $7.5 billion of senior secured recovery bonds. As of December 31, 2025 and December 31, 2024, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.1 billion and $7.2 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

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 December 31, 2025, 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 December 31, 2025, it did not consolidate any of them.
Oakland Headquarters Purchase/Recognition of Lease Assets and Liabilities
Oakland Headquarters Purchase

On June 3, 2025, the Utility completed the purchase of the legal parcel that contains the Oakland General Office. The purchase price was $906 million, of which the Utility had prepaid a total of $400 million. At closing, the Utility assumed a $172 million noncurrent liability for a property assessment carried by the property and paid an additional $349 million, which was adjusted for closing costs. The cash payment is included within the Capital expenditures line item in PG&E Corporation’s and Utility’s Consolidated Statements of Cash Flows, and the property assessment and prepayments are included in Supplemental disclosures of noncash investing and financing activities.
Recognition of Lease Assets and Liabilities

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

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless it can ascertain an implicit discount rate from the leasing arrangement. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense as paid in conformity with ratemaking.

Financing Leases
Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted
Recently Adopted Accounting Standards

Income Taxes

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amended the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. PG&E Corporation and the Utility have applied enhanced disclosure requirements, including, but not limited to, those with respect to PG&E Corporation and the Utility’s income tax rate reconciliation and income taxes paid. This ASU became effective for PG&E Corporation and the Utility on January 1, 2025 and PG&E Corporation and the Utility have applied the enhanced disclosure requirements of ASU 2023-09 on a retrospective basis.

Derivatives and Hedging and Revenue from Contracts with Customers

In September 2025, the FASB issued ASU No. 2025-07, Derivatives and Hedging (Topic 815) and Revenue from Contracts with Customers (Topic 606), which amended the existing guidance to (a) reduce the cost and complexity of evaluating whether contracts with features based on the operations or activities of one of the parties to the contract are derivatives, (b) better portray the economics of those contracts in the financial statements, and (c) reduce diversity in practice resulting from the broad application of the current guidance and changing business environment. The amendments also are expected to reduce diversity in practice by clarifying the applicability of Topic 606, Revenue from Contracts with Customers, to share-based noncash consideration from a customer for the transfer of goods or services. PG&E Corporation and the Utility early adopted the ASU as of December 31, 2025. The adoption of this ASU did not have a significant impact on PG&E Corporation and the Utility’s 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 Consolidated Financial Statements and related disclosures.

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 will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2025, 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 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 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 by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

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

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

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Consolidated Balance Sheets at fair value.
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Summary of Revenues Disaggregated by Type of Customer
The following table presents the Utility’s revenues disaggregated by type of customer:
Year Ended December 31,
(in millions)202520242023
Electric
Revenue from contracts with customers
   Residential$6,976 $7,504 $6,041 
   Commercial7,022 7,201 5,643 
   Industrial1,929 2,065 1,784 
   Agricultural1,825 1,815 1,413 
   Public street and highway lighting105 103 83 
   Other, net (1)
72 (47)136 
      Total revenue from contracts with customers - electric17,929 18,641 15,100 
Regulatory balancing accounts (2)
389 (830)2,324 
Total electric operating revenue$18,318 $17,811 $17,424 
Natural gas
Revenue from contracts with customers
   Residential$3,651 $3,089 $3,686 
   Commercial1,074 984 1,052 
   Transportation service only1,937 1,815 1,603 
   Other, net (1)
101 159 (145)
      Total revenue from contracts with customers - gas6,763 6,047 6,196 
Regulatory balancing accounts (2)
(146)561 808 
Total natural gas operating revenue6,617 6,608 7,004 
Total operating revenues$24,935 $24,419 $24,428 
(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 Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment The Utility’s estimated service lives of its property, plant, and equipment were as follows:
 Estimated ServiceBalance at December 31,
(in millions, except estimated service lives)Lives (years)20252024
Electricity generating facilities (1)
1 to 75
$11,986 $11,420 
Electricity distribution facilities
5 to 70
57,174 49,821 
Electricity transmission facilities
5 to 80
20,959 18,481 
Natural gas distribution facilities
15 to 60
18,240 17,213 
Natural gas transmission and storage facilities
15 to 68
11,315 11,117 
General plant and other
5 to 50
9,315 10,210 
Financing lease2 814 
Construction work in progress4,626 4,458 
Total property, plant, and equipment133,617 123,534 
Accumulated depreciation(37,269)(35,304)
Net property, plant, and equipment (2)
$96,348 $88,230 
(1) Balance includes nuclear fuel inventories, which are stated at weighted-average cost. See Note 15 below. Nuclear generating facilities have been fully depreciated by December 31, 2025.
(2) Includes $2.9 billion of fire risk mitigation-related property, plant, and equipment securitized in accordance with AB 1054.
Changes In Asset Retirement Obligations
The following table summarizes the changes in ARO during 2025 and 2024, including nuclear decommissioning obligations:
(in millions)20252024
ARO liability at beginning of year$5,444 $5,512 
Revision in estimated cash flows(274)(290)
Accretion290 269 
Liabilities settled(21)(47)
ARO liability at end of year$5,439 $5,444 
Schedule Of Government Assistance
The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Consolidated Financial Statements:
(in millions)
202520242023
Long-term debt:
Beginning Balance - DWR loan outstanding
$886 $98 $312 
Proceeds received
— 980 — 
Operating Expenses:
Operating and maintenance expense - Performance-based disbursements
(21)(117)(124)
Operating and maintenance expense - Loan forgiveness and other adjustments
(127)(75)(90)
Long-term debt:
Ending Balance - DWR loan outstanding$738 $886 $98 
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2025 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
Beginning balance$(35)$18 $3 $(14)
Other comprehensive income before reclassifications:
Unrealized loss on investments (net of taxes of $0, $0 and $2, respectively)
— — 5 5 
Unrecognized net actuarial gain (loss) (net of taxes of $84, $25 and $0, respectively)
215 (64)— 151 
Regulatory account transfer (net of taxes of $89, $25 and $0, respectively)
(228)64 — (164)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)
(2)2 — — 
Amortization of net actuarial (gain) loss (net of taxes of $1, $6 and $0, respectively) (1)
1 (15)— (14)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)
2 14 — 16 
Net current period other comprehensive income(12)1 5 (6)
Ending balance$(47)$19 $8 $(20)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.
(2) Includes amounts related to the customer credit trust and self-insurance.
The changes, net of income tax, in PG&E Corporation’s Accumulated other comprehensive income (loss) for the year ended December 31, 2024 consisted of the following:
(in millions, net of income tax)Pension
Benefits		Other
Benefits
Available-for-Sale Securities(2)
Total
Beginning balance$(28)$18 $2 $(8)
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $0, respectively)
— — 1 1 
Unrecognized net actuarial gain (loss) (net of taxes of $104, $11 and $0, respectively)
(268)29 — (239)
Regulatory account transfer (net of taxes of $101, $11 and $0, respectively)
260 (29)— 231 
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)
(2)2 — — 
Amortization of net actuarial (gain) loss (net of taxes of $0, $6 and $0, respectively)(1)
1 (16)— (15)
Regulatory account transfer (net of taxes of $1, $5 and $0, respectively) (1)
2 14 — 16 
Net current period other comprehensive income (loss)(7)— 1 (6)
Ending balance$(35)$18 $3 $(14)
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  See Note 12 below for additional details.
(2) Includes amounts related to the customer credit trust and wildfire self-insurance.
Schedule of Lease Expense
The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
Year Ended December 31,
(in millions)202520242023
Financing lease fixed cost:
Amortization of ROU assets$583 $274 $115 
Interest on lease liabilities16 42 27 
Financing lease variable cost(1)9 3 
Total financing lease costs$598 $325 $145 
The following table shows the lease cost recognized for the fixed and variable component of the Utility’s lease obligations:
Year Ended December 31,
(in millions)202520242023
Operating lease fixed cost$115 $116 $269 
Operating lease variable cost1,487 1,524 1,632 
Total operating lease costs$1,602 $1,640 $1,901 
Schedule of Future Expected Operating Lease Payments
At December 31, 2025, the Utility’s future expected operating lease payments were as follows:
(in millions)December 31, 2025
2026$115 
2027112 
202898 
202964 
203034 
Thereafter165 
Total lease payments588 
Less imputed interest(143)
Total$445 
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)
 12 Months Ended
Dec. 31, 2025
Regulated Operations [Abstract]  
Long-Term Regulatory Assets
Noncurrent regulatory assets are comprised of the following:
 Balance at December 31,Recovery
Period
(in millions)20252024
Pension benefits (1)
$400 $673 Indefinitely
Environmental compliance costs1,158 1,172 32 years
Price risk management100 167 
up to 15.5 years
Catastrophic event memorandum account (2)
666 742 Various
Wildfire-related accounts (3)
1,626 1,697 Various
Deferred income taxes (4)
6,157 4,771 Various
Financing costs (5)
202 216 Various
SB 901 securitization (6)
5,089 5,194 27 years
General rate case memorandum accounts (7)
— 95 Various
Other (8)
583 834 Various
Total noncurrent regulatory assets$15,981 $15,561  
(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
(2) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities.
(3) Represents costs associated with wildfire mitigation and prevention activities and includes the WEMA, FRMMA, WMPMA, WMBA, VMBA and MGMA.
(4) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.
(5) Includes costs associated with long-term debt financing deemed recoverable under ASC 980, Regulated Operations more than twelve months from the current date. These costs and their amortization periods are reviewed and approved in the Utility’s cost of capital or other regulatory filings.
(6) In connection with the SB 901 securitization, the CPUC authorized the issuance of recovery bonds to finance $7.5 billion of claims associated with the 2017 Northern California wildfires. The balance represents PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust, net of amortization since inception. The recovery bonds will be paid through fixed recovery charges, which are designed to recover the full scheduled principal amount of the recovery bonds along with any associated interest and financing costs. See Note 5 below.
(7) The GRC memorandum accounts track the differences between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023 to be collected over 24 months. The balance as of December 31, 2024 included revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014. This revenue is being recognized over 60 months, which began in August 2022.
(8) The balance as of December 31, 2025 includes revenue to be recognized related to gas transmission and storage capital expenditures incurred during the period from 2011 to 2014.
Long-Term Regulatory Liabilities
Noncurrent regulatory liabilities are comprised of the following:
 Balance at December 31,
(in millions)20252024
Cost of removal obligations (1)
$9,488 $8,943 
Public purpose programs (2)
1,169 1,112 
Employee benefit plans (3)
1,043 1,088 
Transmission tower wireless licenses (4)
257 306 
SFGO sale (5)
— 79 
SB 901 securitization (6)
6,010 6,295 
Wildfire self-insurance (7)
1,035 804 
Other (8)
1,186 790 
Total noncurrent regulatory liabilities
$20,188 $19,417 
(1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected through rates for expected costs to remove assets.
(2) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
(3) Represents cumulative differences between incurred costs and amounts collected through rates for post-retirement medical, post-retirement life, and long-term disability plans.
(4) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers through 2042.
(5) Represents the noncurrent portion of the net gain on the sale of the SFGO, which is being distributed to customers over a five-year period that began in 2022.
(6) In connection with the SB 901 securitization, the Utility is required to return up to $7.59 billion of certain shareholder tax benefits to customers via periodic bill credits over the life of the recovery bonds. The balance reflects qualifying shareholder tax benefits that PG&E Corporation is obligated to contribute to the customer credit trust, net of amortization. See Note 5 below.
(7) Represents amounts collected through rates designated for wildfire self-insurance, plus earnings on investments and less operating expenses of wildfire self-insurance. Balance at December 31, 2025 includes amounts collected through both CPUC and FERC rates. Balance at December 31, 2024 includes only amounts collected through CPUC rates. See Note 14 below.
(8) Includes amounts collected through FERC rates designated for wildfire self-insurance at December 31, 2024. See Note 14 below.
Current Regulatory Balancing Accounts Receivable
Current regulatory balancing accounts receivable and payable are comprised of the following:
Receivable
Balance at December 31,
(in millions)20252024
Electric distribution (1)
$1,465 $1,591 
Electric transmission (2)
122 117 
Gas distribution and transmission (3)
142 387 
Energy procurement (4)
2,711 1,066 
Public purpose programs (5)
151 162 
Wildfire-related accounts (6)
84 979 
Insurance premium costs (7)
— 38 
Residential uncollectibles balancing accounts (8)
278 260 
Catastrophic event memorandum account (9)
181 500 
General rate case memorandum accounts (10)
— 1,113 
Other1,166 1,014 
Total regulatory balancing accounts receivable$6,300 $7,227 
Current Regulatory Balancing Accounts Payable
Payable
Balance at December 31,
(in millions)20252024
Electric transmission (2)
$37 $883 
Gas distribution and transmission (3)
78 72 
Energy procurement (4)
1,502 329 
Public purpose programs (5)
472 882 
SFGO sale83 93 
Wildfire-related accounts (6)
338 337 
Nuclear decommissioning adjustment mechanism (11)
1 23 
Other608 550 
Total regulatory balancing accounts payable$3,119 $3,169 
(1) The electric distribution accounts track the collection of revenue requirements approved in the GRC and other proceedings.
(2) The electric transmission accounts track recovery of costs related to the transmission of electricity approved in FERC TO rate cases.
(3) The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and other proceedings.
(4) Energy procurement balancing accounts track recovery of costs related to the procurement of electricity and other revenue requirements approved by the CPUC for recovery in procurement-related balancing accounts, including any environmental compliance-related activities.
(5) The Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for CPUC-mandated programs such as energy efficiency.
(6) The wildfire-related accounts track costs associated with wildfire mitigation and prevention activities and includes the FHPMA, WMPMA, WMBA and VMBA.
(7) The insurance premium costs accounts track the current portion of incremental excess liability insurance costs recorded to the Risk Transfer Balancing Account, as authorized in the 2023 GRC.
(8) The RUBA tracks costs associated with customer protections, including higher uncollectible costs related to limits on electric and gas service disconnections for residential customers.
(9) The CEMA tracks costs associated with responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities which were approved for cost recovery in the 2020 WMCE final decision, 2021 WMCE final decision, 2022 WMCE final decision, and 2023 WMCE final decision.
(10) The GRC memorandum accounts track the difference between the revenue requirements in effect on January 1, 2023 and the revenue requirements authorized by the CPUC in the 2023 GRC final decision in December 2023.
(11) The Nuclear decommissioning adjustment mechanism account tracks the collection of revenue requirements associated with the decommissioning of the Utility’s nuclear facilities which were approved in the 2021 NDCTP final decision.
v3.25.4
DEBT (Tables)
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025:
(in millions)Termination
Date		Maximum Facility LimitLoans OutstandingLetters of Credit OutstandingFacility
Availability
Utility revolving credit facilityJune 2030$5,400 
(1)
$(1,575)$(639)$3,186 
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 $(3,325)$(639)$3,836 
(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.
Schedule of Long-term Debt
The following table summarizes PG&E Corporation’s and the Utility’s Long-term debt:
Balance at
(in millions)Contractual Interest RatesDecember 31, 2025December 31, 2024
PG&E Corporation
Convertible Notes due 20274.25%$2,150 $2,150 
Senior Secured Notes due 20285.00%1,000 1,000 
Senior Secured Notes due 20305.25%1,000 1,000 
Junior Subordinated Notes due 20557.38%1,500 1,500 
Unamortized discount, premium and debt issuance costs, net(29)(39)
Total PG&E Corporation Long-Term Debt5,621 5,611 
Utility
First Mortgage Bonds - Stated Maturity:
2025
3.45% - 4.95%
— 1,925 
2026
 2.95%
600 2,551 
2027
2.10% - 5.45%
3,000 3,000 
2028
3.00% - 5.00%
2,775 1,975 
2029
4.20% - 6.10%
2,100 2,100 
2030
 4.55%
3,100 3,100 
2031
2.50% - 3.25%
3,000 3,000 
2032
4.40% - 5.90%
1,900 1,050 
2033
6.15% - 6.40%
1,900 1,900 
2034
5.80% - 6.95%
1,900 1,900 
2035
5.70% - 6.00%
1,850 — 
2040
3.30% - 4.50%
2,951 2,951 
2041
4.20% - 4.50%
700 700 
2042
3.75% - 4.45%
750 750 
2043
4.60%
375 375 
2044
4.75%
675 675 
2045
4.30%
600 600 
2046
4.00% - 4.25%
1,050 1,050 
2047
3.95%
850 850 
2050
3.50% - 4.95%
5,025 5,025 
2052
5.25%
550 550 
2053
6.70% - 6.75%
2,300 2,300 
20545.90%750 750 
2055
6.10% - 6.15%
1,500 — 
Less: current portion, net of unamortized discount and debt issuance costs(600)(1,924)
Unamortized discount, premium and debt issuance costs, net(247)(226)
Total Utility First Mortgage Bonds39,354 36,927 
Recovery Bonds (1)
10,145 10,367 
         Less: current portion(221)(222)
DWR Loan (2)
738 886 
Credit Facilities
Receivables Securitization Program - Stated Maturity: 2027
variable rate (3)
1,750 — 
Total Utility Long-Term Debt51,766 47,958 
Total PG&E Corporation Consolidated Long-Term Debt$57,387 $53,569 
(1) The amount includes bonds related to AB 1054 and SB 901 securitization transactions. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
(2) The Utility is not required to pay interest on the DWR loan, see Note 2 - Government Assistance.
(3) At December 31, 2025, the contractual SOFR-based interest rate on the Receivables Securitization Program was 5.31%.
Schedule Of Long Term Debt Repayments
PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2025 are reflected in the table below:
       
(in millions, except interest rates)20262027202820292030ThereafterTotal
PG&E Corporation
Average fixed interest rate— %4.25 %5.00 %— %5.25 %7.38 %5.39 %
Fixed rate obligations$— $2,150 $1,000 $— $1,000 $1,500 $5,650 
Utility (1)
Average fixed interest rate2.95 %3.22 %3.99 %5.52 %4.55 %4.90 %4.69 %
Fixed rate obligations$600 $3,000 $2,775 $2,100 $3,100 $28,626 $40,201 
Variable interest rate as of December 31, 2025
— %5.31 %— %— %— %— %5.31 %
Variable rate obligations
$— $1,750 $— $— $— $— $1,750 
Recovery Bonds (2)
AB 1054 obligations$81 $84 $88 $91 $95 $2,633 $3,072 
SB 901 obligations140 146 152 159 165 6,311 7,073 
Total consolidated debt$821 $7,130 $4,015 $2,350 $4,360 $39,070 $57,746 
(1) The balance excludes the DWR loan, see Note 2 - Government Assistance.
(2) Recovery bonds were issued by, and are repayment obligations of, consolidated VIEs. For AB 1054 interest rates, see the 2021 Form 10-K, the 2022 Form 10-K, and the 2024 Form 10-K. For SB 901 interest rates, see the 2022 Form 10-K.
v3.25.4
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Tables)
 12 Months Ended
Dec. 31, 2025
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)
20252024
Balance at January 1
$5,194 $5,249 
Amortization
(105)(55)
Balance at December 31
$5,089 $5,194 
SB 901 securitization regulatory liability
(in millions)
20252024
Balance at January 1
$(6,295)$(6,628)
Amortization
407 383 
Additions(1)
(122)(50)
Balance at December 31
$(6,010)$(6,295)
(1) Includes $87 million and $16 million of returns on investments in the customer credit trust expected to be credited to customers for the years ended December 31, 2025 and 2024, respectively.
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)
 12 Months Ended
Dec. 31, 2025
Common Stock And Share-Based Compensation [Abstract]  
Schedule of Dividend Paid on Common Stock
The following table summarizes the dividends on common stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation common stock$0.025 $55 November 29, 2024December 31, 2024January 15, 2025
0.02555 February 20, 2025March 31, 2025April 15, 2025
0.02555 May 22, 2025June 30, 2025July 15, 2025
0.02555 September 18, 2025September 30, 2025October 15, 2025
0.05110 December 11, 2025December 31, 2025January 15, 2026
Utility common stock
(1)
575 February 20, 2025
(1)
March 18, 2025
(1)
575 May 22, 2025
(1)
May 30, 2025
(1)
575 September 18, 2025
(1)
September 26, 2025
(1)
625 December 11, 2025
(1)
December 18, 2025
(1) PG&E Corporation owns all of the outstanding shares of Utility common stock.
The following table summarizes the dividends on preferred stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation mandatory convertible preferred stock$0.7167 $23 December 12, 2024February 14, 2025February 27, 2025
0.75 24 February 20, 2025May 15, 2025May 29, 2025
0.75 24 May 22, 2025August 15, 2025August 28, 2025
0.75 24 September 18, 2025November 14, 2025December 1, 2025
0.75 24 December 11, 2025February 13, 2026March 1, 2026
Utility preferred stockvaries by series3.5 November 29, 2024January 31, 2025February 15, 2025
varies by series3.5 February 20, 2025April 30, 2025May 15, 2025
varies by series3.5 May 22, 2025July 31, 2025August 15, 2025
varies by series3.5 September 18, 2025October 31, 2025November 15, 2025
varies by series3.5 December 11, 2025January 30, 2026February 15, 2026
Schedule of Compensation Expense for Share-based Incentive Awards
The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards:
(in millions)
202520242023
Restricted stock units80 67 64 
Performance shares54 31 27 
Total compensation expense (pre-tax)$134 $98 $91 
Total compensation expense (after-tax)$97 $71 $65 
Summary of Stock Option Activity
The following table summarizes stock option activity for PG&E Corporation and the Utility for 2025:
Number of
Stock Options		Weighted Average Grant-
Date Fair Value		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1743,963 $10.23 
Granted (1)
— — 
Exercised— — 
Forfeited or expired(111,495)10.23 
Outstanding at December 31632,468 10.23 1.91
Vested or expected to vest at December 31632,468 10.23 1.91
Exercisable at December 31632,468 $10.23 1.91
(1) Represents additional payout of existing stock option grants.
Schedule of Restricted Stock Units
The following table summarizes restricted stock unit activity for 2025:
Number of
Restricted Stock Units		Weighted Average Grant-
Date Fair Value
Nonvested at January 19,423,582 $15.52 
Granted6,252,871 16.43 
Vested(4,744,176)14.66 
Forfeited(254,623)16.21 
Nonvested at December 3110,677,654 $16.42 
Schedule of Performance Shares
The following table summarizes activity for performance shares in 2025:
Number of
Performance Shares		Weighted Average Grant-
Date Fair Value
Nonvested at January 17,180,206 $15.52 
Granted2,445,690 15.10 
Vested(2,831,269)11.21 
Forfeited
(332,132)16.39 
Nonvested at December 316,462,495 $16.40 
v3.25.4
PREFERRED STOCK (Tables)
 12 Months Ended
Dec. 31, 2025
Preferred Stock [Abstract]  
Schedule of Dividend Paid or Declared on Preferred Stock
The following table summarizes the dividends on common stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation common stock$0.025 $55 November 29, 2024December 31, 2024January 15, 2025
0.02555 February 20, 2025March 31, 2025April 15, 2025
0.02555 May 22, 2025June 30, 2025July 15, 2025
0.02555 September 18, 2025September 30, 2025October 15, 2025
0.05110 December 11, 2025December 31, 2025January 15, 2026
Utility common stock
(1)
575 February 20, 2025
(1)
March 18, 2025
(1)
575 May 22, 2025
(1)
May 30, 2025
(1)
575 September 18, 2025
(1)
September 26, 2025
(1)
625 December 11, 2025
(1)
December 18, 2025
(1) PG&E Corporation owns all of the outstanding shares of Utility common stock.
The following table summarizes the dividends on preferred stock paid or declared by PG&E Corporation and the Utility in 2025:
SecurityAmount per ShareAggregate amount (in millions)Date of DeclarationRecord DatePayment Date
PG&E Corporation mandatory convertible preferred stock$0.7167 $23 December 12, 2024February 14, 2025February 27, 2025
0.75 24 February 20, 2025May 15, 2025May 29, 2025
0.75 24 May 22, 2025August 15, 2025August 28, 2025
0.75 24 September 18, 2025November 14, 2025December 1, 2025
0.75 24 December 11, 2025February 13, 2026March 1, 2026
Utility preferred stockvaries by series3.5 November 29, 2024January 31, 2025February 15, 2025
varies by series3.5 February 20, 2025April 30, 2025May 15, 2025
varies by series3.5 May 22, 2025July 31, 2025August 15, 2025
varies by series3.5 September 18, 2025October 31, 2025November 15, 2025
varies by series3.5 December 11, 2025January 30, 2026February 15, 2026
v3.25.4
EARNINGS PER SHARE (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Schedule of Earnings Per Share, Diluted, by Common Class, Including Two Class Method The following is a reconciliation of PG&E Corporation’s income (loss) available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2025, 2024, and 2023.
 Year Ended December 31,
(in millions, except per share amounts)202520242023
Income available for common shareholders$2,593 $2,475 $2,242 
Weighted average common shares outstanding, basic (1)
2,197 2,141 2,064 
Add incremental shares from assumed conversions:
Employee share-based compensation
5 6 6 
Equity Units— — 68 
Weighted average common shares outstanding, diluted2,202 2,147 2,138 
Total earnings per common share, diluted$1.18 $1.15 $1.05 
(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.
v3.25.4
INCOME TAXES (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax Expense (Benefit)
The significant components of income tax expense (benefit) were as follows:
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)202520242023202520242023
Current:      
Federal$(1)$2 $(1)$(1)$2 $(1)
State50 (78)— 89 (78)— 
Deferred:
Federal(225)(137)(1,047)(171)(72)(981)
State(102)15 (507)(109)45 (477)
Federal tax credits(2)(2)(2)(2)(2)(2)
Total income tax benefit
$(280)$(200)$(1,557)$(194)$(105)$(1,461)
Schedule of Deferred Tax Assets and Liabilities
 PG&E CorporationUtility
 
Year Ended December 31,
(in millions)2025202420252024
Deferred income tax assets:    
Tax carryforwards$9,752 $9,429 $9,199 $8,955 
Compensation211 171 127 86 
GHG allowances457 471 457 471 
Wildfire-related claims (1)
227 295 227 295 
Operating lease liability
111 78 111 78 
Transmission tower wireless license251 251 251 251 
Bad debt137 127 137 127 
Other (2)
127 140 156 137 
Total deferred income tax assets$11,273 $10,962 $10,665 $10,400 
Deferred income tax liabilities:    
Property-related basis difference12,357 11,021 12,344 11,009 
Regulatory balancing accounts487 878 487 878 
Income tax regulatory asset (3)
1,723 1,335 1,723 1,335 
Debt financing costs353 390 353 390 
Operating lease ROU asset111 78 111 78 
Environmental reserve288 248 288 248 
Other (4)
89 94 91 94 
Total deferred income tax liabilities$15,408 $14,044 $15,397 $14,032 
Total net deferred income tax liabilities$4,135 $3,082 $4,732 $3,632 
(1) Amounts primarily relate to wildfire-related claims, net of recoveries, and legal and other costs related to various wildfires that have occurred in the Utility’s service area over the past several years.
(2) Amounts include benefits, state taxes, and customer advances for construction.
(3) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax.
(4) Amounts primarily include property taxes.
Schedule of Effective Income Tax Rate Reconciliation
The following tables reconcile income tax expense at the federal statutory rate to the income tax provision:
 PG&E Corporation
 Year Ended December 31,
(in millions)202520242023
Federal statutory income tax rate21.0 %$486 21.0 %$478 21.0 %$144 
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(1.8)(41)(2.0)(45)(57.9)(397)
Effect of regulatory treatment of fixed asset differences (2)
(34.2)(790)(28.9)(657)(62.4)(428)
Changes in valuation allowance
0.8 18 (0.9)(20)0.7 5 
Nontaxable or nondeductible items
2.2 51 0.8 19 0.2 1 
Tax credits(1.1)(26)(1.0)(22)(3.4)(24)
Changes in unrecognized tax benefits0.1 3 2.1 46 0.2 2 
Fire Victim Trust (3)
— — — — (126.9)(869)
Other, net0.9 19 0.1 1 1.3 9 
Effective tax rate(12.1)%$(280)(8.8)%$(200)(227.2)%$(1,557)
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.

 Utility
 Year Ended December 31,
(in millions)202520242023
Federal statutory income tax rate21.0 %$606 21.0 %$547 21.0 %$228 
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)
(0.6)(16)(0.8)(22)(34.4)(373)
Effect of regulatory treatment of fixed asset differences (2)
(27.4)(790)(25.2)(657)(39.5)(428)
Changes in valuation allowance— — — — 0.1 1 
Nontaxable or nondeductible items1.1 30 0.4 12 — — 
Tax credits(0.9)(26)(0.9)(22)(2.2)(24)
Changes in unrecognized tax benefits
0.1 3 1.9 49 0.2 2 
Fire Victim Trust (3)
— — — — (80.2)(869)
Other, net— (1)(0.4)(12)0.2 2 
Effective tax rate(6.7)%$(194)(4.0)%$(105)(134.8)%$(1,461)
(1) Includes the effect of state flow-through ratemaking treatment.
(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.
(3) Includes an adjustment for the tax benefit of the sale of shares by the Fire Victim Trust in 2023.
Schedule of Change in Unrecognized Tax Benefits
The following table reconciles the changes in unrecognized tax benefits:
 PG&E CorporationUtility
(in millions)202520242023202520242023
Balance at beginning of year$454 $616 $570 $454 $616 $570 
Additions for tax position taken during a prior year5 — 1 5 — 1 
Reductions for tax position taken during a prior year(7)(257)— (7)(257)— 
Additions for tax position taken during the current year665 95 45 665 95 45 
Balance at end of year
$1,117 $454 $616 $1,117 $454 $616 
Schedule of Operating Loss and Tax Credit Carryforward Balances
The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:
(in millions)December 31, 2025Expiration
Year
Federal:  
Net operating loss carryforward - Pre-2018$3,307 2031 - 2036
Net operating loss carryforward - Post-201734,957 N/A
Tax credit carryforward226 Various
State:
Net operating loss carryforward$34,143 2039 - 2041
Tax credit carryforward167 Various
v3.25.4
DERIVATIVES (Tables)
 12 Months Ended
Dec. 31, 2025
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 ProductInstrumentsDecember 31, 2025December 31, 2024
Natural Gas (1) (MMBtus (2))
Forwards, futures, and swaps232,825,834 179,257,247 
 Options48,215,000 37,717,500 
Electricity (MWh)Forwards, futures, and swaps7,196,942 8,576,078 
Options1,650,800 1,663,200 
 
Congestion Revenue Rights (3)
93,712,644 123,040,895 
(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
(2) Million British Thermal Units.
(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.
Offsetting Liabilities
As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal 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 

As of December 31, 2024, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal Derivative
Balance
Current assets – other$186 $(16)$170 
Noncurrent assets – other233 — 233 
Current liabilities – other(152)16 (136)
Noncurrent liabilities – other(167)— (167)
Total commodity risk$100 $— $100 
Offsetting Assets
As of December 31, 2025, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal 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 

As of December 31, 2024, the Utility’s outstanding derivative balances were as follows:
 Commodity Risk
(in millions)Gross Derivative
Balance		NettingTotal Derivative
Balance
Current assets – other$186 $(16)$170 
Noncurrent assets – other233 — 233 
Current liabilities – other(152)16 (136)
Noncurrent liabilities – other(167)— (167)
Total commodity risk$100 $— $100 
v3.25.4
FAIR VALUE MEASUREMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.
 Fair Value Measurements
 
At December 31, 2025
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments
$634 $— $— $— $634 
Fixed-income securities— — — — — 
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 10)
     
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 10)
     
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 Measurements
 
At December 31, 2024
(in millions)Level 1Level 2Level 3
Netting (1)
Total
Assets:     
Short-term investments$826 $— $— $— $826 
Pacific Energy Risk Solutions, LLC
  Short-term investments905 — — — 905 
Total Pacific Energy Risk Solutions, LLC905 — — — 905 
Nuclear decommissioning trusts
Short-term investments53 — — — 53 
Global equity securities2,228 — — — 2,228 
Fixed-income securities1,250 1,027 — — 2,277 
Assets measured at NAV— — — — 22 
Total nuclear decommissioning trusts (2)
3,531 1,027 — — 4,580 
Customer credit trust
Short-term investments1 — — — 1 
Global equity securities186 — — — 186 
Fixed-income securities46 144 — — 190 
Total customer credit trust
233 144 — — 377 
Price risk management instruments (Note 10)
    
Electricity— 26 383 (6)403 
Gas— 10 — (10)— 
Total price risk management instruments— 36 383 (16)403 
Rabbi trusts    
Short-term investments107 — — — 107 
Global equity securities6 — — — 6 
Life insurance contracts— 66 — — 66 
Total rabbi trusts113 66 — — 179 
Long-term disability trust    
Short-term investments4 — — — 4 
Assets measured at NAV— — — — 130 
Total long-term disability trust4 — — — 134 
TOTAL ASSETS$5,612 $1,273 $383 $(16)$7,404 
Liabilities:    
Price risk management instruments (Note 10)
    
Electricity$— $37 $248 $(6)$279 
Gas— 34 — (10)24 
TOTAL LIABILITIES$— $71 $248 $(16)$303 
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.
(2) Represents amount before deducting $747 million primarily related to deferred taxes on appreciation of investment value.
Fair Value Measurement Inputs and Valuation Techniques
 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.

 Fair Value
(in millions)		   
At December 31, 2024Valuation
Technique		Unobservable
Input		 
Fair Value MeasurementAssetsLiabilities
 Range (1)/Weighted-Average Price (2)
Congestion revenue rights$366 $121 Market approachCRR auction prices
$ (951) - 50,044 / 2
Power purchase agreements$17 $127 Discounted cash flowForward prices
$ 0 - 126 / 47
(1) Represents price per MWh.
(2) Unobservable inputs were weighted by the relative fair value of the instruments.
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2025 and 2024:
 Price Risk Management Instruments
(in millions)20252024
Asset balance as of January 1$127 $191 
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)
26 (64)
Asset balance as of December 31$153 $127 
(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets, and net income is not impacted.
Carrying Amount and Fair Value of Financial Instruments
The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
 
At December 31, 2025
At December 31, 2024
(in millions)Carrying AmountLevel 2 Fair Value
Carrying Amount
Level 2 Fair Value
Debt (Note 4)    
PG&E Corporation (1)
$5,360 $5,697 $5,358 $5,829 
Utility38,145 35,565 37,812 34,532 
(1) As of December 31, 2025, 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 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 
As of December 31, 2024    
Nuclear decommissioning trusts    
Short-term investments$54 $— $(1)$53 
Global equity securities353 1,907 (10)2,250 
Fixed-income securities2,341 20 (84)2,277 
Total (1)
$2,748 $1,927 $(95)$4,580 
(1) Represents amounts before deducting $881 million and $747 million as of December 31, 2025 and December 31, 2024, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Available for Sale Securities Table
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2025
Less than 1 year$95 
1–5 years822 
5–10 years564 
More than 10 years1,077 
Total maturities of fixed-income securities$2,558 
The following table provides a summary of equity securities and available-for-sale debt securities:
(in millions)Amortized
Cost		Total
Unrealized
Gains		Total
Unrealized
Losses		Total Fair
Value
As of December 31, 2025
Customer credit trust
Short-term investments$111 $— $— $111 
Global equity securities— — — — 
Fixed-income securities689 5 (1)693 
Total
$800 $5 $(1)$804 
As of December 31, 2024    
Customer credit trust    
Short-term investments$1 $— $— $1 
Global equity securities161 28 (3)186 
Fixed-income securities193 1 (4)190 
Total
$355 $29 $(7)$377 
Schedule of Activity for Debt and Equity Securities
The following table provides a summary of activity for the fixed-income and equity securities:
(in millions)202520242023
Proceeds from sales and maturities of nuclear decommissioning trust investments$1,952 $1,980 $2,235 
Gross realized gains on securities213 255 80 
Gross realized losses on securities(25)(63)(74)
The fair value of fixed-income securities by contractual maturity is as follows:
 As of
(in millions)December 31, 2025
Less than 1 year$290 
1–5 years107 
5–10 years49 
More than 10 years247 
Total maturities of fixed-income securities$693 
The following table provides a summary of activity for the fixed-income and equity securities:
(in millions)202520242023
Proceeds from sales and maturities of customer credit trust investments$435 $398 $556 
Gross realized gains on securities131 10$23 
Gross realized losses on securities
(20)(8)$(19)
v3.25.4
EMPLOYEE BENEFIT PLANS (Tables)
 12 Months Ended
Dec. 31, 2025
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]  
Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2025 and 2024:

Pension Plan
(in millions)20252024
Change in plan assets:
Fair value of plan assets at beginning of year$16,767 $17,211 
Actual return on plan assets1,779 218 
Company contributions337 337 
Benefits and expenses paid(1,020)(999)
Fair value of plan assets at end of year$17,863 $16,767 
Change in benefit obligation:
Benefit obligation at beginning of year$17,585 $17,697 
Service cost for benefits earned424 396 
Interest cost1,007 916 
Actuarial loss (gain) (1)
427 (424)
Benefits and expenses paid(1,020)(1,000)
Benefit obligation at end of year (2)
$18,423 $17,585 
Funded Status:
Current liability$(10)$(10)
Noncurrent liability(550)(808)
Net liability at end of year
$(560)$(818)
(1) The actuarial loss for the year ended December 31, 2025 was due to a decrease in the discount rate used to measure the projected benefit obligation and unfavorable changes in demographic assumptions; the actuarial gain for the year ended December 31, 2024 was due to an increase in the discount rate used to measure the projected benefit obligation, offset by an unfavorable return on plan assets and unfavorable changes in the demographic assumptions.
(2) PG&E Corporation’s accumulated benefit obligation was $16.5 billion and $15.8 billion at December 31, 2025 and 2024, respectively.
Postretirement Benefits Other than Pensions
(in millions)20252024
Change in plan assets:
Fair value of plan assets at beginning of year$2,471 $2,499 
Actual return on plan assets200 74 
Company contributions7 5 
Plan participant contribution91 84 
Benefits and expenses paid(196)(191)
Fair value of plan assets at end of year$2,573 $2,471 
Change in benefit obligation:
Benefit obligation at beginning of year$1,279 $1,377 
Service cost for benefits earned38 41 
Interest cost73 71 
Actuarial loss (gain) (1)
125 (123)
Benefits and expenses paid(182)(174)
Federal subsidy on benefits paid4 3 
Plan participant contributions91 84 
Benefit obligation at end of year$1,428 $1,279 
Funded Status: (2)
Noncurrent asset$1,144 $1,192 
Noncurrent liability— — 
Net asset at end of year$1,144 $1,192 
(1) The actuarial loss for the year ended December 31, 2025 was primarily due to a decrease in the discount rate used to measure the accumulated benefit obligations and unfavorable changes in claims cost, medical trends, and demographic assumptions. The actuarial gain for the year ended December 31, 2024 was primarily due to an increase in the discount rate used to measure the accumulated benefit obligations and favorable changes in demographic assumptions, offset by an unfavorable return on plan assets.
(2) At December 31, 2025 and 2024, the postretirement medical plan and the postretirement life insurance plan were in overfunded positions. The projected benefit obligation and the fair value of plan assets for the postretirement life insurance plan were $274 million and $322 million as of December 31, 2025, and $261 million and $296 million as of December 31, 2024, respectively.
Components of Net Periodic Benefit Cost
Net periodic benefit costs as reflected in PG&E Corporation’s Consolidated Statements of Income were as follows:

Pension Plan
(in millions)202520242023
Service cost for benefits earned (1)
$424 $396 $379 
Interest cost1,007 916 913 
Expected return on plan assets(1,053)(1,014)(981)
Amortization of prior service cost(3)(3)(4)
Amortization of net actuarial loss2 1 1 
Net periodic benefit cost377 296 308 
Less: transfer to regulatory account (2)
(40)39 25 
Total expense recognized$337 $335 $333 
(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.
(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery through future rates.

Postretirement Benefits Other than Pensions
(in millions)202520242023
Service cost for benefits earned (1)
$38 $41 $38 
Interest cost73 71 73 
Expected return on plan assets(150)(139)(132)
Amortization of prior service cost3 3 3 
Amortization of net actuarial gain(23)(23)(19)
Net periodic benefit cost$(59)$(47)$(37)
(1) A portion of service costs are capitalized pursuant to ASC 715, Compensation - Retirement Benefits.
Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost
The following weighted average year-end actuarial assumptions were used in determining the plans’ projected benefit obligations and net benefit costs.
 Pension PlanPBOP Plans
 December 31,December 31,
 202520242023202520242023
Discount rate5.58 %5.76 %5.21 %
5.51 - 5.60%
5.71 - 5.76%
5.18 - 5.22%
Rate of future compensation increases4.80 %4.80 %3.80 %N/AN/AN/A
Expected return on plan assets7.00 %6.40 %6.00 %
4.30 - 7.20%
3.90 - 7.20%
3.70 - 7.00%
Interest crediting rate for cash balance plan4.23 %4.41 %3.86 %N/AN/AN/A
Target Asset Allocation Percentages
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
 Pension PlanPBOP Plans
 202620252024202620252024
Global equity securities28 %26 %26 %14 %30 %29 %
Absolute return1 1 1 — — — 
Real assets6 8 8 3 3 3 
Fixed-income securities65 65 65 83 67 68 
Total100 %100 %100 %100 %100 %100 %
Schedule of Changes in Fair Value of Plan Assets
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2025 and 2024.
 Fair Value Measurements
 At December 31,
 20252024
(in millions)Level 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Pension Plan:        
Short-term investments$452 $30 $— $482 $126 $47 $— $173 
Global equity securities1,445 — — 1,445 1,310 — — 1,310 
Real assets2 — — 2 437 — — 437 
Fixed-income securities1,990 6,880 12 8,882 2,180 6,367 16 8,563 
Assets measured at NAV— — — 7,052 — — — 6,284 
Total$3,889 $6,910 $12 $17,863 $4,053 $6,414 $16 $16,767 
PBOP Plans:        
Short-term investments$546 $— $— $546 $27 $— $— $27 
Global equity securities2 — — 2 60 — — 60 
Real assets— — — — 20 — — 20 
Fixed-income securities518 561 — 1,079 431 751 1 1,183 
Assets measured at NAV— — — 946 — — — 1,181 
Total$1,066 $561 $— $2,573 $538 $751 $1 $2,471 
Total plan assets at fair value   $20,436    $19,238 
Schedule of Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2025 and 2024:
(in millions)
For the year ended December 31, 2025
Fixed-Income
Balance at beginning of year$16 
Actual return on plan assets:
Relating to assets still held at the reporting date7 
Relating to assets sold during the period(7)
Purchases, issuances, sales, and settlements:
Purchases6 
Settlements(10)
Balance at end of year$12 
  
(in millions)
For the year ended December 31, 2024
Fixed-Income
Balance at beginning of year$13 
Actual return on plan assets:
Relating to assets still held at the reporting date9 
Relating to assets sold during the period(9)
Purchases, issuances, sales, and settlements:
Purchases14 
Settlements(11)
Balance at end of year$16 
Schedule of Estimated Benefits Expected to be Paid
As of December 31, 2025, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
(in millions)Pension
Plan		PBOP
Plans		Federal
Subsidy
2026993 84 (1)
20271,082 86 (1)
20281,110 90 (1)
20291,136 93 (1)
20301,161 96 (1)
2031-20356,159 523 (6)
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Tables)
 12 Months Ended
Dec. 31, 2025
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 December 31, 2025.
Payments (in millions)
2019 Kincade Fire
$1,287 
2021 Dixie Fire1,908 
2022 Mosquito Fire107 
Total at December 31, 2025
$3,302 
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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$267 
Accrued Losses100 
Payments(329)
Balance at December 31, 2025
$38 
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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$567 
Accrued Losses225 
Payments(549)
Balance at December 31, 2025
$243 
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, 2024.
Loss Accrual (in millions)
Balance at December 31, 2024
$82 
Accrued Losses250 
Payments(89)
Balance at December 31, 2025
$243 
Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of December 31, 2025 are:
Potential Recovery Source (in millions)2021 Dixie fire2022 Mosquito fire
Insurance$521 $363 
FERC TO rates
97 7 
WEMA
535 54 
Wildfire Fund
1,150 — 
Probable recoveries at December 31, 2025 (1)
$2,303 $424 
(1) Includes legal costs of $148 million and $73 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of December 31, 2025.
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, 2024:
Insurance Receivable (in millions)2021 Dixie fire2022 Mosquito fireTotal
Balance at December 31, 2024
$27 $90 $117 
Accrued insurance recoveries
(6)273 267 
Reimbursements
(20)(82)(102)
Balance at December 31, 2025
$1 $281 $282 
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, 2024:
Wildfire Fund Receivable (in millions)2021 Dixie fire
Balance at December 31, 2024
$756 
Accrued Wildfire Fund recoveries225 
Claims paid by Wildfire Fund(682)
Balance at December 31, 2025
$299 
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Schedule of Environmental Remediation Liability The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Consolidated Balance Sheets and is comprised of the following:
 Balance at
(in millions)December 31, 2025December 31, 2024
Topock natural gas compressor station$315 $294 
Hinkley natural gas compressor station99 97 
Former MGP sites owned by the Utility or third parties (1)
715 782 
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)
71 76 
Fossil fuel-fired generation facilities and sites (3)
17 18 
Total environmental remediation liability$1,217 $1,267 
(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 December 31, 2025
(in millions)Low end of the rangeHigh end of the range
HSMA Recovery (1)
Topock natural gas compressor station (2)
$315 $518 Available
Hinkley natural gas compressor station (2)
99 221 Unavailable
Former MGP sites owned by the Utility or third parties (3)
715 1,292 Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)
71 146 Available
Fossil fuel-fired generation facilities and sites (5)
17 32 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.
Schedule of Undiscounted Future Expected Power Purchase Agreement Payments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2025:
 Power Purchase Agreements   
(in millions)Renewable
Energy		Conventional
Energy		Natural
Gas
Other (1)
Total
2026$1,937 $1,058 $544 $278 $3,817 
20271,921 1,035 193 134 3,283 
20281,903 989 106 47 3,045 
20291,858 905 98 6 2,867 
20301,852 510 42 2 2,406 
Thereafter12,828 4,315 34 5 17,182 
Total purchase commitments$22,299 $8,812 $1,017 $472 $32,600 
(1) Includes other power purchase agreements and nuclear fuel agreements.
Schedule of Other Commitments At December 31, 2025, the future minimum payments related to these commitments were as follows:
(in millions)Other Commitments
2026$82 
202751 
202841 
202939 
203013 
Thereafter65 
Total minimum payments$291 
v3.25.4
ORGANIZATION AND BASIS OF PRESENTATION (Details)
 12 Months Ended
Dec. 31, 2025
reportableSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Number of operating segments (segment) 1
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Segment Reporting) (Narrative) (Details)
 12 Months Ended
Dec. 31, 2025
reportableSegment
Accounting Policies [Abstract]  
Number of reportable segments 1
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Cash, Cash Equivalents, and Restricted Cash, and Restricted Cash Equivalents) (Narrative) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Public Utility, Property, Plant and Equipment [Line Items]      
Restricted cash and cash equivalents $ 259 $ 273 $ 297
Utility      
Public Utility, Property, Plant and Equipment [Line Items]      
Restricted cash and cash equivalents $ 258 $ 272 $ 294
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Revenue Recognition) (Narrative) (Details)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Period for probable revenue recovery 24 months
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Revenues Disaggregated by Type of Customer) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Abstract]      
Total operating revenues $ 24,935 $ 24,419 $ 24,428
Electric      
Disaggregation of Revenue [Abstract]      
Total operating revenues 18,318 17,811 17,424
Natural gas      
Disaggregation of Revenue [Abstract]      
Total operating revenues 6,617 6,608 7,004
Utility      
Disaggregation of Revenue [Abstract]      
Total operating revenues 24,935 24,419 24,428
Utility | Electric      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 17,929 18,641 15,100
Regulatory balancing accounts 389 (830) 2,324
Total operating revenues 18,318 17,811 17,424
Utility | Electric | Residential      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 6,976 7,504 6,041
Utility | Electric | Commercial      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 7,022 7,201 5,643
Utility | Electric | Industrial      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 1,929 2,065 1,784
Utility | Electric | Agricultural      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 1,825 1,815 1,413
Utility | Electric | Public street and highway lighting      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 105 103 83
Utility | Electric | Other, net      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 72 (47) 136
Utility | Natural gas      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 6,763 6,047 6,196
Regulatory balancing accounts (146) 561 808
Total operating revenues 6,617 6,608 7,004
Utility | Natural gas | Residential      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 3,651 3,089 3,686
Utility | Natural gas | Commercial      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 1,074 984 1,052
Utility | Natural gas | Transportation service only      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers 1,937 1,815 1,603
Utility | Natural gas | Other, net      
Disaggregation of Revenue [Abstract]      
Total revenue from contracts with customers $ 101 $ 159 $ (145)
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Financial Assets Measured at Amortized Cost – Credit Losses) (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Public Utility, Property, Plant and Equipment [Line Items]      
Credit losses $ 402 $ 341 $ 636
Regulatory assets 15,981 15,561  
Regulatory Balancing Accounts Receivable      
Public Utility, Property, Plant and Equipment [Line Items]      
Total regulatory balancing accounts 6,300 7,227  
FERC TO rates      
Public Utility, Property, Plant and Equipment [Line Items]      
Regulatory assets 92 85  
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable      
Public Utility, Property, Plant and Equipment [Line Items]      
Total regulatory balancing accounts $ 278 $ 260  
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utilities Property, Plant and Equipment) (Details) - Utility - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 133,617 $ 123,534
Accumulated depreciation (37,269) (35,304)
Net property, plant, and equipment 96,348 88,230
Electricity generating facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment 11,986 11,420
Electricity generating facilities | Northern California Wildfire    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 2,900  
Electricity generating facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 1 year  
Electricity generating facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 75 years  
Electricity distribution facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 57,174 49,821
Electricity distribution facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 5 years  
Electricity distribution facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 70 years  
Electricity transmission facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 20,959 18,481
Electricity transmission facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 5 years  
Electricity transmission facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 80 years  
Natural gas distribution facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 18,240 17,213
Natural gas distribution facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 15 years  
Natural gas distribution facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 60 years  
Natural gas transmission and storage facilities    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 11,315 11,117
Natural gas transmission and storage facilities | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 15 years  
Natural gas transmission and storage facilities | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 68 years  
General plant and other    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 9,315 10,210
General plant and other | Minimum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 5 years  
General plant and other | Maximum    
Public Utility, Property, Plant and Equipment [Line Items]    
Estimated Useful Lives (years) 50 years  
Financing lease    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 2 814
Construction work in progress    
Public Utility, Property, Plant and Equipment [Line Items]    
Total property, plant, and equipment $ 4,626 $ 4,458
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Property, Plant and Equipment) (Narrative) (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Utility    
Public Utility, Property, Plant and Equipment [Line Items]    
Composite depreciation rate 3.77% 3.61%
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Allowance for Funds Used During Construction) (Narrative) (Details) - Utility - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Public Utility, Property, Plant and Equipment [Line Items]      
AFUDC debt recorded $ 88 $ 111 $ 82
AFUDC equity recorded $ 219 $ 184 $ 179
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
ARO liability at beginning of year $ 5,444 $ 5,512
Revision in estimated cash flows (274) (290)
Accretion 290 269
Liabilities settled (21) (47)
ARO liability at end of year $ 5,439 $ 5,444
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Asset Retirement Obligation) (Narrative) (Details) - USD ($)
$ in Billions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Utility    
Public Utility, Property, Plant and Equipment [Line Items]    
Nuclear decommissioning obligation accrued $ 4.2 $ 4.0
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Nuclear Decommissioning Trusts) (Narrative) (Details)
 12 Months Ended
Dec. 31, 2025
facility
Diablo Canyon | Utility  
Public Utility, Property, Plant and Equipment [Line Items]  
Number of generation facilities 2
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Government Assistance) (Details) - USD ($)
 12 Months Ended
Jan. 11, 2024
Oct. 18, 2022
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Senate Bill 846 | Utility          
Public Utility, Property, Plant and Equipment [Line Items]          
Debt instrument, face amount   $ 1,100,000,000      
Senate Bill 846 | Utility | Maximum          
Public Utility, Property, Plant and Equipment [Line Items]          
Debt instrument, face amount   1,400,000,000      
Performance-Based Disbursement          
Public Utility, Property, Plant and Equipment [Line Items]          
Disbursement   7      
Reimbursement amount         $ 56,000,000
Maximum disbursement   $ 300,000,000      
Civil Nuclear Credit Program          
Public Utility, Property, Plant and Equipment [Line Items]          
Maximum disbursement $ 1,100,000,000        
Civil Nuclear Credit Program | Cost of Goods and Services Sold, Electricity          
Public Utility, Property, Plant and Equipment [Line Items]          
Reimbursement amount     $ 65,000,000 $ 265,000,000 115,000,000
Civil Nuclear Credit Program | Utilities Operating Expense, Maintenance and Operations          
Public Utility, Property, Plant and Equipment [Line Items]          
Reimbursement amount     69,000,000 $ 138,000,000 $ 76,000,000
Civil Nuclear Credit Program, Incurred Fuel Costs          
Public Utility, Property, Plant and Equipment [Line Items]          
Disbursement     $ 13,000,000    
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Schedule Of DWR Loan Activity) (Details) - DWR Loan - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Government Assistance, Liability [Roll Forward]      
Beginning balance $ 886 $ 98 $ 312
Proceeds received $ 0 $ 980 $ 0
Government Assistance, Liability, Increase, Statement of Financial Position [Extensible Enumeration] Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates)
Ending balance $ 738 $ 886 $ 98
Government Assistance, Liability, Statement of Financial Position [Extensible Enumeration] Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates) Long-term debt (includes $11.7 billion and $10.1 billion related to VIEs at respective dates)
Performance-Based Disbursements      
Government Assistance, Liability [Roll Forward]      
Total deduction $ (21) $ (117) $ (124)
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration] Operating and maintenance Operating and maintenance Operating and maintenance
Loan forgiveness and other adjustments      
Government Assistance, Liability [Roll Forward]      
Total deduction $ (127) $ (75) $ (90)
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration] Operating and maintenance Operating and maintenance Operating and maintenance
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (VIE) (Narrative) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
recoveryBond
Dec. 31, 2024
USD ($)
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 $ 3,200 $ 3,200    
Receivables Securitization Program - Stated Maturity: 2027 | Utility        
Public Utility, Property, Plant and Equipment [Line Items]        
Long-term debt, gross 1,750 0    
Recovery Bonds | Secured Debt        
Public Utility, Property, Plant and Equipment [Line Items]        
Long-term debt, gross 10,145 10,367    
Debt instrument, face amount 3,100 3,200 $ 3,260  
SB 901 securitization | Secured Debt        
Public Utility, Property, Plant and Equipment [Line Items]        
Debt instrument, face amount $ 7,100 $ 7,200   $ 7,500
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Wildfire Fund) (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Jul. 12, 2019
Public Utility, Property, Plant and Equipment [Line Items]        
Litigation liability, current $ 193      
Wildfire Fund asset 297 $ 301    
Litigation contribution, net 3,700      
Amortization and accretion 352 383 $ 567  
Utility        
Public Utility, Property, Plant and Equipment [Line Items]        
Wildfire Fund asset 297 301    
Amortization and accretion 352 $ 383 $ 567  
Other Current Liabilities        
Public Utility, Property, Plant and Equipment [Line Items]        
Wildfire fund, noncurrent $ 377      
Wildfire Fund Asset        
Public Utility, Property, Plant and Equipment [Line Items]        
Finite-lived intangible asset, useful life   20 years   15 years
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Oakland Headquarters Purchase) (Narrative) (Details) - Utility - Oakland General Office
$ in Millions
Jun. 03, 2025
USD ($)
Asset Acquisition [Line Items]  
Purchase price $ 906
Purchase price, deposits 400
Asset acquisition, recognized identifiable assets acquired and liabilities assumed, debt 172
Additional payment $ 349
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance $ 30,401 $ 25,292
Unrealized gain (loss) on investments 5 1
Net current period other comprehensive gain (loss) (6) (6)
Ending balance 32,792 30,401
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) (12) (7)
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) 1 0
Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Unrealized gain (loss) on investments 5 1
Amount attributable to tax, before reclassification 2 0
Net current period other comprehensive gain (loss) 5 1
Accumulated Other Comprehensive Income (Loss)    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (14) (8)
Ending balance (20) (14)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Beginning balance (35) (28)
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 18 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 3 2
Ending balance 8 3
Amortization of net actuarial loss (gain)    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 151 (239)
Amounts reclassified from other comprehensive income (14) (15)
Amortization of net actuarial loss (gain) | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 215 (268)
Other comprehensive income before reclassifications, tax 84 104
Amounts reclassified from other comprehensive income 1 1
Amount attributable to tax, reclassification 1 0
Amortization of net actuarial loss (gain) | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: (64) 29
Other comprehensive income before reclassifications, tax 25 11
Amounts reclassified from other comprehensive income (15) (16)
Amount attributable to tax, reclassification 6 6
Amortization of net actuarial loss (gain) | Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 0 0
Other comprehensive income before reclassifications, tax 0 0
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]    
Other comprehensive income before reclassifications: (164) 231
Amounts reclassified from other comprehensive income 16 16
Regulatory account transfer | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: (228) 260
Other comprehensive income before reclassifications, tax 89 101
Amounts reclassified from other comprehensive income 2 2
Amount attributable to tax, reclassification 1 1
Regulatory account transfer | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 64 (29)
Other comprehensive income before reclassifications, tax 25 11
Amounts reclassified from other comprehensive income 14 14
Amount attributable to tax, reclassification 5 5
Regulatory account transfer | Available-for-Sale Securities    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Other comprehensive income before reclassifications: 0 0
Other comprehensive income before reclassifications, tax 0 0
Amounts reclassified from other comprehensive income 0 0
Amount attributable to tax, reclassification 0 0
Amortization of prior service cost    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 0 0
Amortization of prior service cost | Pension Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income (2) (2)
Amount attributable to tax, reclassification 1 1
Amortization of prior service cost | Other Benefits    
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]    
Amounts reclassified from other comprehensive income 2 2
Amount attributable to tax, reclassification 1 1
Amortization of prior service cost | 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
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Leases) (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lessee, Lease, Description [Line Items]      
Cash payments for financing lease $ 26 $ 315 $ 142
Weighted average remaining lease term, finance lease 4 years 1 month 6 days 6 months  
Weighted average discount rate, finance lease 4.60% 6.20%  
Lease payments $ 1,600 $ 1,600 $ 1,900
Weighted average remaining lease term. operating lease 7 years 1 month 6 days 7 years 6 months  
Weighted average discount rate, operating lease 6.60% 6.50%  
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Financing lease fixed cost:      
Amortization of ROU assets $ 583 $ 274 $ 115
Interest on lease liabilities 16 42 27
Financing lease variable cost (1) 9 3
Total financing lease costs 598 325 145
Operating Lease Costs [Abstract]      
Operating lease fixed cost 115 116 269
Operating lease variable cost 1,487 1,524 1,632
Total operating lease costs $ 1,602 $ 1,640 $ 1,901
v3.25.4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Future Expected Operating Lease Payments  
2026 $ 115
2027 112
2028 98
2029 64
2030 34
Thereafter 165
Total lease payments 588
Less imputed interest (143)
Total $ 445
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Jun. 30, 2022
Feb. 28, 2022
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 15,981 $ 15,561    
Customer harm threshold, post-emergence transaction, recovery bonds issued       $ 7,500
Initial shareholder contribution 2,000      
Pension benefits        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets 400 673    
Environmental compliance costs        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 1,158 1,172    
Recovery Period 32 years      
Price risk management        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 100 167    
Recovery Period 15 years 6 months      
Catastrophic event memorandum account        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 666 742    
Wildfire-related accounts        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets 1,626 1,697    
Deferred income taxes        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets 6,157 4,771    
Financing costs        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets 202 216    
SB 901 securitization        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 5,089 5,194 $ 5,500  
Recovery Period 27 years      
General rate case memorandum accounts        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 0 95    
Other        
Regulatory Assets [Line Items]        
Total noncurrent regulatory assets $ 583 $ 834    
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS - (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Regulatory Liabilities [Line Items]      
Interest income $ 520 $ 604 $ 606
Regulatory Balancing Accounts Payable      
Regulatory Liabilities [Line Items]      
Interest income 223 323 257
Regulatory Balancing Accounts Receivable      
Regulatory Liabilities [Line Items]      
Interest income 419 537 547
Utility      
Regulatory Liabilities [Line Items]      
Current regulatory liabilities 965 1,200  
Interest income $ 509 $ 589 $ 593
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Jun. 30, 2022
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities $ 20,188 $ 19,417  
Authorized amount of shareholder tax benefits to be returned 7,590    
Cost of removal obligations      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 9,488 8,943  
Public purpose programs      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,169 1,112  
Employee benefit plans      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,043 1,088  
Transmission tower wireless licenses      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 257 306  
SFGO sale      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 0 79  
SB 901 securitization      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 6,010 6,295 $ 5,540
Wildfire self-insurance      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities 1,035 804  
Other      
Regulatory Liabilities [Line Items]      
Total noncurrent regulatory liabilities $ 1,186 $ 790  
v3.25.4
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts $ 3,119 $ 3,169
Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 6,300 7,227
Electric distribution | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 1,465 1,591
Electric transmission | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 37 883
Electric transmission | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 122 117
Gas distribution and transmission | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 78 72
Gas distribution and transmission | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 142 387
Energy procurement | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 1,502 329
Energy procurement | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 2,711 1,066
Public purpose programs | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 472 882
Public purpose programs | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 151 162
SFGO sale | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 83 93
Wildfire-related accounts | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 338 337
Wildfire-related accounts | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 84 979
Insurance premium costs | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 0 38
Residential uncollectibles balancing accounts | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 278 260
Catastrophic event memorandum account | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 181 500
General rate case memorandum accounts | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 0 1,113
Nuclear decommissioning adjustment mechanism | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 1 23
Other | Regulatory Balancing Accounts Payable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts 608 550
Other | Regulatory Balancing Accounts Receivable    
Regulatory Assets [Line Items]    
Total regulatory balancing accounts $ 1,166 $ 1,014
v3.25.4
DEBT (Outstanding Borrowings and Availability) (Details) - USD ($)
Dec. 31, 2025
Jun. 26, 2025
Jun. 23, 2025
Jun. 22, 2025
Dec. 31, 2024
Utility revolving credit facility          
Debt [Line Items]          
Maximum Facility Limit $ 7,800,000,000        
Loans Outstanding (3,325,000,000)        
Letters of Credit Outstanding (639,000,000)        
Facility Availability 3,836,000,000        
Utility revolving credit facility | PG&E Corporation revolving credit facility          
Debt [Line Items]          
Maximum Facility Limit 650,000,000   $ 650,000,000 $ 500,000,000  
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   $ 5,400,000,000 $ 4,400,000,000  
Loans Outstanding (1,575,000,000)        
Letters of Credit Outstanding (639,000,000)        
Facility Availability 3,186,000,000        
Letter of credit sublimit 2,000,000,000        
Utility Receivables Securitization Program | Utility          
Debt [Line Items]          
Maximum Facility Limit 1,750,000,000 $ 1,500,000,000      
Loans Outstanding (1,750,000,000)       $ 0
Letters of Credit Outstanding 0        
Facility Availability $ 0        
v3.25.4
DEBT (Narrative) (Details)
 12 Months Ended
Dec. 19, 2025
USD ($)
Sep. 24, 2025
USD ($)
Jun. 26, 2025
USD ($)
Apr. 11, 2025
USD ($)
Dec. 04, 2023
USD ($)
day
$ / shares
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Oct. 02, 2025
USD ($)
Jun. 23, 2025
USD ($)
Jun. 22, 2025
USD ($)
Jun. 04, 2025
USD ($)
Feb. 24, 2025
USD ($)
Debt [Line Items]                          
Debt financial instrument           $ 57,387,000,000 $ 53,569,000,000            
Repayments of long-term debt           3,876,000,000 800,000,000 $ 3,075,000,000          
Utility                          
Debt [Line Items]                          
Repayments of long-term debt           3,876,000,000 800,000,000 3,075,000,000          
364 Day 2024 Term Loan | Utility                          
Debt [Line Items]                          
Debt instrument, face amount $ 600,000,000     $ 525,000,000                  
364 Day 2024 Term Loan | Utility | SOFR                          
Debt [Line Items]                          
Credit spread adjustment       0.10%                  
Basis spread on variable rate 1.25%     1.375%                  
364 Day 2024 Term Loan | Utility | Base Rate                          
Debt [Line Items]                          
Basis spread on variable rate 0.25%     0.375%                  
Utility revolving credit facility                          
Debt [Line Items]                          
Maximum Facility Limit           7,800,000,000              
Utility revolving credit facility | PG&E Corporation                          
Debt [Line Items]                          
Maximum Facility Limit           650,000,000       $ 650,000,000 $ 500,000,000    
Utility revolving credit facility | Utility                          
Debt [Line Items]                          
Maximum Facility Limit           5,400,000,000       $ 5,400,000,000 $ 4,400,000,000    
Receivables Securitization Program - Stated Maturity: 2027 | Utility                          
Debt [Line Items]                          
Maximum Facility Limit     $ 1,500,000,000     $ 1,750,000,000              
Line of credit facility, increase (decrease), net     $ 250,000,000                    
Interest rate           5.31%              
Debt financial instrument           $ 1,750,000,000 0            
Term Loan | Utility                          
Debt [Line Items]                          
Debt instrument, face amount   $ 500,000,000                      
Term Loan | Utility | SOFR                          
Debt [Line Items]                          
Basis spread on variable rate   1.25%                      
Term Loan | Utility | Base Rate                          
Debt [Line Items]                          
Basis spread on variable rate   0.25%                      
First Mortgage Bonds Due 2035 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                       $ 850,000,000 $ 1,000,000,000.0
Interest rate                       6.00% 5.70%
First Mortgage Bonds Due 2055 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                 $ 750,000,000       $ 750,000,000
Interest rate                 6.10%       6.15%
First Mortgage Bonds Due June 15, 2025 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                         $ 600,000,000
Interest rate                         3.50%
First Mortgage Bonds Due June 8, 2025 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                         $ 450,000,000
Interest rate                         4.95%
First Mortgage Bonds Due 2028 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                 $ 400,000,000     $ 400,000,000  
Interest rate                 5.00%     5.00%  
First Mortgage Bonds Due January 1, 2026 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                 $ 1,900,000,000     $ 1,900,000,000  
Interest rate                 3.15%     3.15%  
First Mortgage Bonds Due 2032 | Utility                          
Debt [Line Items]                          
Debt instrument, face amount                 $ 850,000,000        
Interest rate                 5.05%        
Convertible Notes due 2027 | PG&E Corporation                          
Debt [Line Items]                          
Interest rate           4.25%              
Repayments of long-term debt         $ 2,150,000,000                
Convertible Notes due 2027 | PG&E Corporation | Secured Debt                          
Debt [Line Items]                          
Debt instrument, face amount         $ 2,150,000,000                
Interest rate         4.25%                
Debt financial instrument         $ 2,120,000,000 $ 2,140,000,000 2,130,000,000            
Conversion price | $ / shares         $ 23.18                
Debt instrument, redemption price, percentage         100.00%                
Debt issuance costs           13,000,000 20,000,000            
Interest expense           $ 91,000,000 $ 98,000,000 $ 7,000,000          
Conversion rate         0.0431416                
Convertible Notes due 2027 | PG&E Corporation | Secured Debt | Debt Conversion Terms One                          
Debt [Line Items]                          
Threshold trading days | day         20                
Threshold consecutive trading days | day         30                
Threshold percentage of stock price         130.00%                
Convertible Notes due 2027 | PG&E Corporation | Secured Debt | Debt Conversion Terms Two                          
Debt [Line Items]                          
Threshold trading days | day         5                
Threshold consecutive trading days | day         10                
Threshold percentage of stock price         90.00%                
v3.25.4
DEBT (Schedule of Long-term Debt) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 04, 2023
Debt [Line Items]      
Less: current portion, net of unamortized discount and debt issuance costs $ (821) $ (2,146)  
Long-term debt, net 57,387 53,569  
Utility      
Debt [Line Items]      
Less: current portion, net of unamortized discount and debt issuance costs (821) (2,146)  
New Debt | Utility      
Debt [Line Items]      
Long-term debt, net 51,766 47,958  
New Debt | PG&E Corporation      
Debt [Line Items]      
Unamortized discount, premium and debt issuance costs, net (29) (39)  
Long-term debt, net $ 5,621 5,611  
Convertible Notes due 2027 | PG&E Corporation      
Debt [Line Items]      
Contractual Interest Rates 4.25%    
Long-term debt, gross $ 2,150 2,150  
Convertible Notes due 2027 | PG&E Corporation | Secured Debt      
Debt [Line Items]      
Contractual Interest Rates     4.25%
Long-term debt, net $ 2,140 2,130 $ 2,120
Senior Secured Notes due 2028 | PG&E Corporation      
Debt [Line Items]      
Contractual Interest Rates 5.00%    
Long-term debt, gross $ 1,000 1,000  
Senior Secured Notes due 2030 | PG&E Corporation      
Debt [Line Items]      
Contractual Interest Rates 5.25%    
Long-term debt, gross $ 1,000 1,000  
Junior Subordinated Notes due 2055 | PG&E Corporation      
Debt [Line Items]      
Contractual Interest Rates 7.38%    
Long-term debt, gross $ 1,500 1,500  
First Mortgage Bonds | Utility      
Debt [Line Items]      
Less: current portion, net of unamortized discount and debt issuance costs (600) (1,924)  
Unamortized discount, premium and debt issuance costs, net (247) (226)  
Long-term debt, net 39,354 36,927  
First Mortgage Bonds, Stated Maturity 2025 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 0 1,925  
First Mortgage Bonds, Stated Maturity 2025 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.45%    
First Mortgage Bonds, Stated Maturity 2025 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.95%    
First Mortgage Bonds, Stated Maturity 2026 | Utility      
Debt [Line Items]      
Contractual Interest Rates 2.95%    
Long-term debt, gross $ 600 2,551  
First Mortgage Bonds, Stated Maturity 2027 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 3,000 3,000  
First Mortgage Bonds, Stated Maturity 2027 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 2.10%    
First Mortgage Bonds, Stated Maturity 2027 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 5.45%    
First Mortgage Bonds, Stated Maturity 2028 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 2,775 1,975  
First Mortgage Bonds, Stated Maturity 2028 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.00%    
First Mortgage Bonds, Stated Maturity 2028 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 5.00%    
First Mortgage Bonds Due 2029 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 2,100 2,100  
First Mortgage Bonds Due 2029 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 4.20%    
First Mortgage Bonds Due 2029 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.10%    
First Mortgage Bonds, Stated Maturity 2030 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 3,100 3,100  
First Mortgage Bonds, Stated Maturity 2030 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.55%    
First Mortgage Bonds, Stated Maturity 2031 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 3,000 3,000  
First Mortgage Bonds, Stated Maturity 2031 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 2.50%    
First Mortgage Bonds, Stated Maturity 2031 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 3.25%    
First Mortgage Bonds, Stated Maturity 2032 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,900 1,050  
First Mortgage Bonds, Stated Maturity 2032 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 4.40%    
First Mortgage Bonds, Stated Maturity 2032 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 5.90%    
First Mortgage Bonds Due 2033 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,900 1,900  
First Mortgage Bonds Due 2033 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 6.15%    
First Mortgage Bonds Due 2033 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.40%    
First Mortgage Bonds Due 2034 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,900 1,900  
First Mortgage Bonds Due 2034 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 5.80%    
First Mortgage Bonds Due 2034 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.95%    
First Mortgage Bonds, Stated Maturity 2035 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,850 0  
First Mortgage Bonds, Stated Maturity 2035 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 5.70%    
First Mortgage Bonds, Stated Maturity 2035 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.00%    
First Mortgage Bonds, Stated Maturity 2040 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 2,951 2,951  
First Mortgage Bonds, Stated Maturity 2040 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.30%    
First Mortgage Bonds, Stated Maturity 2040 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.50%    
First Mortgage Bonds, Stated Maturity 2041 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 700 700  
First Mortgage Bonds, Stated Maturity 2041 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 4.20%    
First Mortgage Bonds, Stated Maturity 2041 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.50%    
First Mortgage Bonds, Stated Maturity 2042 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 750 750  
First Mortgage Bonds, Stated Maturity 2042 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.75%    
First Mortgage Bonds, Stated Maturity 2042 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.45%    
First Mortgage Bonds, Stated Maturity 2043 | Utility      
Debt [Line Items]      
Contractual Interest Rates 4.60%    
Long-term debt, gross $ 375 375  
First Mortgage Bonds, Stated Maturity 2044 | Utility      
Debt [Line Items]      
Contractual Interest Rates 4.75%    
Long-term debt, gross $ 675 675  
First Mortgage Bonds, Stated Maturity 2045 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 600 600  
First Mortgage Bonds, Stated Maturity 2045 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 4.30%    
First Mortgage Bonds, Stated Maturity 2046 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,050 1,050  
First Mortgage Bonds, Stated Maturity 2046 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 4.00%    
First Mortgage Bonds, Stated Maturity 2046 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.25%    
First Mortgage Bonds, Stated Maturity 2047 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 850 850  
First Mortgage Bonds, Stated Maturity 2047 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.95%    
First Mortgage Bonds, Stated Maturity 2050 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 5,025 5,025  
First Mortgage Bonds, Stated Maturity 2050 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 3.50%    
First Mortgage Bonds, Stated Maturity 2050 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 4.95%    
First Mortgage Bonds, Stated Maturity 2052 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 550 550  
First Mortgage Bonds, Stated Maturity 2052 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 5.25%    
First Mortgage Bonds, Stated Maturity 2053 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 2,300 2,300  
First Mortgage Bonds, Stated Maturity 2053 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 6.70%    
First Mortgage Bonds, Stated Maturity 2053 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.75%    
First Mortgage Bonds, Stated Maturity 2054 | Utility      
Debt [Line Items]      
Contractual Interest Rates 5.90%    
Long-term debt, gross $ 750 750  
First Mortgage Bonds, Stated Maturity 2055 | Utility      
Debt [Line Items]      
Long-term debt, gross $ 1,500 0  
First Mortgage Bonds, Stated Maturity 2055 | Utility | Minimum      
Debt [Line Items]      
Contractual Interest Rates 6.10%    
First Mortgage Bonds, Stated Maturity 2055 | Utility | Maximum      
Debt [Line Items]      
Contractual Interest Rates 6.15%    
Recovery Bonds | Secured Debt      
Debt [Line Items]      
Long-term debt, gross $ 10,145 10,367  
Less: current portion, net of unamortized discount and debt issuance costs (221) (222)  
DWR Loan      
Debt [Line Items]      
Long-term debt, net $ 738 886  
Receivables Securitization Program - Stated Maturity: 2027 | Utility      
Debt [Line Items]      
Contractual Interest Rates 5.31%    
Long-term debt, gross $ 1,750 0  
Long-term debt, net $ 1,750 $ 0  
v3.25.4
DEBT (Schedule of Contractual Repayment Schedule) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Debt [Line Items]  
Total consolidated debt $ 57,746
AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 3,072
SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 7,073
Utility  
Debt [Line Items]  
Average fixed interest rate 4.69%
Fixed rate obligations $ 40,201
Variable interest rate as of December 31, 2025 5.31%
Variable rate obligations $ 1,750
PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 5.39%
Fixed rate obligations $ 5,650
2026  
Debt [Line Items]  
Total consolidated debt 821
2026 | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 81
2026 | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 140
2026 | Utility  
Debt [Line Items]  
Average fixed interest rate 2.95%
Fixed rate obligations $ 600
Variable interest rate as of December 31, 2025 0.00%
Variable rate obligations $ 0
2026 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
2027  
Debt [Line Items]  
Total consolidated debt 7,130
2027 | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 84
2027 | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 146
2027 | Utility  
Debt [Line Items]  
Average fixed interest rate 3.22%
Fixed rate obligations $ 3,000
Variable interest rate as of December 31, 2025 5.31%
Variable rate obligations $ 1,750
2027 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 4.25%
Fixed rate obligations $ 2,150
2028  
Debt [Line Items]  
Total consolidated debt 4,015
2028 | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 88
2028 | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 152
2028 | Utility  
Debt [Line Items]  
Average fixed interest rate 3.99%
Fixed rate obligations $ 2,775
Variable interest rate as of December 31, 2025 0.00%
Variable rate obligations $ 0
2028 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 5.00%
Fixed rate obligations $ 1,000
2029  
Debt [Line Items]  
Total consolidated debt 2,350
2029 | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 91
2029 | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 159
2029 | Utility  
Debt [Line Items]  
Average fixed interest rate 5.52%
Fixed rate obligations $ 2,100
Variable interest rate as of December 31, 2025 0.00%
Variable rate obligations $ 0
2029 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 0.00%
Fixed rate obligations $ 0
2030  
Debt [Line Items]  
Total consolidated debt 4,360
2030 | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 95
2030 | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 165
2030 | Utility  
Debt [Line Items]  
Average fixed interest rate 4.55%
Fixed rate obligations $ 3,100
Variable interest rate as of December 31, 2025 0.00%
Variable rate obligations $ 0
2030 | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 5.25%
Fixed rate obligations $ 1,000
Thereafter  
Debt [Line Items]  
Total consolidated debt 39,070
Thereafter | AB 1054 obligations  
Debt [Line Items]  
Fixed rate obligations 2,633
Thereafter | SB 901 obligations  
Debt [Line Items]  
Fixed rate obligations $ 6,311
Thereafter | Utility  
Debt [Line Items]  
Average fixed interest rate 4.90%
Fixed rate obligations $ 28,626
Variable interest rate as of December 31, 2025 0.00%
Variable rate obligations $ 0
Thereafter | PG&E Corporation  
Debt [Line Items]  
Average fixed interest rate 7.38%
Fixed rate obligations $ 1,500
v3.25.4
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Narrative) (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Jun. 30, 2022
Dec. 31, 2025
Dec. 31, 2024
Debt [Line Items]      
Regulatory assets   $ 15,981 $ 15,561
Initial shareholder contribution   2,000  
Regulatory liabilities   20,188 19,417
SB 901 securitization      
Debt [Line Items]      
Regulatory liabilities $ 5,540 6,010 6,295
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   302 328
Nothern California Wild Fire      
Debt [Line Items]      
Loss contingency, costs incurred 7,500    
SB 901 securitization      
Debt [Line Items]      
Regulatory assets $ 5,500 $ 5,089 $ 5,194
v3.25.4
SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST (Financial Statement Impact) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
SB 901 securitization regulatory asset    
Beginning balance $ 15,561  
Ending balance 15,981 $ 15,561
SB 901 securitization regulatory liability    
Beginning balance (19,417)  
Ending balance (20,188) (19,417)
SB 901 Securitization Inception    
SB 901 securitization regulatory liability    
Beginning balance (6,295) (6,628)
Amortization 407 383
Additions (122) (50)
Ending balance (6,010) (6,295)
Increase in regulatory liabilities 122 50
SB 901 Securitization Inception | Customer credit trust    
SB 901 securitization regulatory liability    
Additions (87) (16)
Increase in regulatory liabilities 87 16
SB 901 Securitization Inception    
SB 901 securitization regulatory asset    
Beginning balance 5,194 5,249
Amortization (105) (55)
Ending balance $ 5,089 $ 5,194
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($)
 12 Months Ended
Dec. 04, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Schedule of Capitalization, Equity [Line Items]        
Common stock, shares outstanding (in shares)   2,197,942,874 2,193,573,536  
Investment plan, term   5 years    
Shares available for LTIP award (in shares)   51,401,320    
Granted (in dollars per share)   $ 16.43 $ 16.74 $ 15.70
Total fair value   $ 70,000,000 $ 62,000,000 $ 64,000,000
Total unrecognized compensation costs   $ 108,000,000    
Remaining weighted average period   1 year 7 months 6 days    
Employee Stock Option        
Schedule of Capitalization, Equity [Line Items]        
Granted (in shares)   0 0  
Weighted-average period   1 year 1 month 20 days    
Restricted stock units        
Schedule of Capitalization, Equity [Line Items]        
Award vesting period   3 years    
Tax detriment   $ 8,000,000    
Performance shares        
Schedule of Capitalization, Equity [Line Items]        
Award vesting period   3 years    
Industry performance period   3 years    
Award grant date fair value recognition period   3 years    
Performance shares granted (in dollars per share)   $ 15.10 $ 16.94 $ 13.39
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized   $ 39,000,000    
2014 LTIP, Amended        
Schedule of Capitalization, Equity [Line Items]        
Number of shares issued for LTIP, maximum (in shares)   91,000,000    
2014 LTIP | Employee Stock Option        
Schedule of Capitalization, Equity [Line Items]        
Term of award   10 years    
Award vesting period   3 years    
Total unrecognized compensation costs   $ 0    
Granted (in shares)   0    
Over-Allotment Option        
Schedule of Capitalization, Equity [Line Items]        
Preferred Stock issued, net $ 1,130,000,000      
Utility        
Schedule of Capitalization, Equity [Line Items]        
Common stock, shares outstanding (in shares)   477,743,590    
Common stock issued, net (in shares) 55,961,070      
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION - (Schedule of Dividend Paid) (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended 12 Months Ended
Dec. 11, 2025
Sep. 18, 2025
May 22, 2025
Feb. 20, 2025
Nov. 29, 2024
Dec. 31, 2025
Sep. 30, 2025
Jun. 30, 2025
Mar. 31, 2025
Dec. 31, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Schedule of Capitalization, Equity [Line Items]                          
Common stock dividends declared                     $ 277 $ 120 $ 21
Utility                          
Schedule of Capitalization, Equity [Line Items]                          
Common stock dividends declared $ 625 $ 575 $ 575 $ 575                  
PG&E Corporation                          
Schedule of Capitalization, Equity [Line Items]                          
Common stock dividend declared (in dollars per share)           $ 0.05 $ 0.025 $ 0.025 $ 0.025 $ 0.025      
Common stock dividends declared $ 110 $ 55 $ 55 $ 55 $ 55                
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) $ 134 $ 98 $ 91
Total compensation expense (after-tax) 97 71 65
Restricted stock units      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) 80 67 64
Performance shares      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Total compensation expense (pre-tax) $ 54 $ 31 $ 27
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - Employee Stock Option - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Number of Stock Options    
Granted (in shares) 0 0
2014 LTIP    
Number of Stock Options    
Outstanding, beginning of period (in shares) 743,963  
Granted (in shares) 0  
Exercised (in shares) 0  
Forfeited or expired (in shares) (111,495)  
Outstanding, end of period (in shares) 632,468 743,963
Vested or expected to vest (in shares) 632,468  
Exercisable (in shares) 632,468  
Weighted Average Grant- Date Fair Value    
Outstanding, beginning of period (in dollars per share) $ 10.23  
Forfeited or expired (in dollars per share) 10.23  
Outstanding, end of period (in dollars per share) 10.23 $ 10.23
Vested or expected to vest (in dollars per share) 10.23  
Exercisable (in dollars per share) $ 10.23  
Weighted Average Remaining Contractual Term (Years)    
Outstanding 1 year 10 months 28 days  
Vested or expected to vest 1 year 10 months 28 days  
Exercisable 1 year 10 months 28 days  
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Number of Restricted Stock Units      
Nonvested, beginning balance (in shares) 9,423,582    
Granted (in shares) 6,252,871    
Vested (in shares) (4,744,176)    
Forfeited (in shares) (254,623)    
Nonvested, ending balance (in shares) 10,677,654 9,423,582  
Weighted Average Grant- Date Fair Value      
Nonvested, beginning balance (in dollars per share) $ 15.52    
Granted (in dollars per share) 16.43 $ 16.74 $ 15.70
Vested (in dollars per share) 14.66    
Forfeited (in dollars per share) 16.21    
Nonvested, ending balance (in dollars per share) $ 16.42 $ 15.52  
v3.25.4
COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Number of Performance Shares      
Nonvested , beginning balance (in shares) 7,180,206    
Granted (in shares) 2,445,690    
Vested (in shares) (2,831,269)    
Forfeited (in shares) (332,132)    
Nonvested, ending balance (in shares) 6,462,495 7,180,206  
Weighted Average Grant- Date Fair Value      
Nonvested, beginning balance (in dollars per share) $ 15.52    
Granted (in dollars per share) 15.10 $ 16.94 $ 13.39
Vested (in dollars per share) 11.21    
Forfeited (in dollars per share) 16.39    
Nonvested, ending balance (in dollars per share) $ 16.40 $ 15.52  
v3.25.4
PREFERRED STOCK - Narrative (Details)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 05, 2024
USD ($)
$ / shares
shares
Dec. 31, 2025
USD ($)
$ / shares
shares
Dec. 31, 2024
USD ($)
$ / shares
Preferred Stock [Line Items]      
Preferred Stock issued, net | $     $ 1,579
Investment plan, term   5 years  
$25 Par Value | Utility      
Preferred Stock [Line Items]      
Preferred stock, shares authorized (in shares) | shares   75,000,000  
Preferred stock, par value (in dollars per share)   $ 25  
$100 Par Value | Utility      
Preferred Stock [Line Items]      
Preferred stock, shares authorized (in shares) | shares   10,000,000  
Preferred stock, par value (in dollars per share)   $ 100  
Preferred stock, shares outstanding (in shares) | shares   0  
Maximum | Utility      
Preferred Stock [Line Items]      
Redemption price (in dollars per share)   $ 27.25 $ 27.25
Minimum | Utility      
Preferred Stock [Line Items]      
Redemption price (in dollars per share)   $ 25.75 $ 25.75
6.000% Series A Mandatory Convertible Preferred Stock, no par value      
Preferred Stock [Line Items]      
Preferred stock, shares issued (in shares) | shares 32,200,000    
Preferred stock interest rate 6.00%    
Preferred stock, par value (in dollars per share) $ 50.00    
Preferred Stock issued, net | $ $ 1,600    
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Maximum      
Preferred Stock [Line Items]      
Preferred stock, convertible, conversion ratio 2.4331    
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Minimum      
Preferred Stock [Line Items]      
Preferred stock, convertible, conversion ratio 1.9465    
Nonredeemable Preferred Stock | Utility      
Preferred Stock [Line Items]      
Nonredeemable preferred stock outstanding | $   $ 145 $ 145
Preferred stock dividends per share, low range (in dollars per share)   $ 1.25  
Preferred stock dividends per share, high range (in dollars per share)   $ 1.50  
Nonredeemable Preferred Stock | Maximum | Utility      
Preferred Stock [Line Items]      
Preferred stock interest rate   6.00%  
Nonredeemable Preferred Stock | Minimum | Utility      
Preferred Stock [Line Items]      
Preferred stock interest rate   5.00%  
Redeemable Preferred Stock | Utility      
Preferred Stock [Line Items]      
Redeemable preferred stock outstanding | $   $ 113 $ 113
Preferred stock dividends per share, low range (in dollars per share)   $ 1.09  
Preferred stock dividends per share, high range (in dollars per share)   $ 1.25  
Redeemable Preferred Stock | Maximum | Utility      
Preferred Stock [Line Items]      
Preferred stock interest rate     5.00%
Redeemable Preferred Stock | Minimum | Utility      
Preferred Stock [Line Items]      
Preferred stock interest rate     4.36%
PG&E Corporation      
Preferred Stock [Line Items]      
Preferred stock, shares authorized (in shares) | shares   400,000,000  
v3.25.4
PREFERRED STOCK - (Schedule of Dividend Paid or Declared) (Details) - USD ($)
$ / shares in Units, $ in Millions
 3 Months Ended 12 Months Ended
Dec. 11, 2025
Sep. 18, 2025
May 22, 2025
Feb. 20, 2025
Dec. 12, 2024
Nov. 29, 2024
Dec. 31, 2025
Sep. 30, 2025
Jun. 30, 2025
Mar. 31, 2025
Dec. 31, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Preferred Stock [Line Items]                            
Preferred stock dividend requirement                       $ 110.0 $ 37.0 $ 14.0
6.000% Series A Mandatory Convertible Preferred Stock, no par value | Utility                            
Preferred Stock [Line Items]                            
Preferred stock dividend requirement $ 3.5 $ 3.5 $ 3.5 $ 3.5   $ 3.5                
PG&E Corporation | 6.000% Series A Mandatory Convertible Preferred Stock, no par value                            
Preferred Stock [Line Items]                            
Preferred stock, dividends declared (in dollars per share)             $ 0.75 $ 0.75 $ 0.75 $ 0.75 $ 0.7167      
Preferred stock dividend requirement $ 24.0 $ 24.0 $ 24.0 $ 24.0 $ 23.0                  
v3.25.4
EARNINGS PER SHARE (Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Shares of Common Stock Outstanding for Calculating Diluted EPS) (Details) - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Income available for common shareholders, basic $ 2,593 $ 2,475 $ 2,242
Income available for common shareholders diluted $ 2,593 $ 2,475 $ 2,242
Weighted average common shares outstanding, basic (in shares) 2,197,000,000 2,141,000,000 2,064,000,000
Add incremental shares from assumed conversions:      
Weighted average common share outstanding, diluted (in shares) 2,202,000,000 2,147,000,000 2,138,000,000
Diluted (in dollars per share) $ 1.18 $ 1.15 $ 1.05
PG&E Corporation      
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Income available for common shareholders, basic $ 2,593 $ 2,475 $ 2,242
Income available for common shareholders diluted $ 2,593 $ 2,475 $ 2,242
Weighted average common shares outstanding, basic (in shares) 2,197,000,000 2,141,000,000 2,064,000,000
Add incremental shares from assumed conversions:      
Employee share-based compensation 5,000,000 6,000,000 6,000,000
Equity Units (in shares) 0 0 68,000,000
Weighted average common share outstanding, diluted (in shares) 2,202,000,000 2,147,000,000 2,138,000,000
Diluted (in dollars per share) $ 1.18 $ 1.15 $ 1.05
Number of shares sold (in shares) 477,743,590 477,743,590 477,743,590
v3.25.4
INCOME TAXES (Schedule of Income Tax Expense (Benefit) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current:      
Federal $ (1,000) $ 2,000 $ (1,000)
State 50,000 (78,000) 0
Deferred:      
Federal (225,000) (137,000) (1,047,000)
State (102,000) 15,000 (507,000)
Federal tax credits (2,000) (2,000) (2,000)
Total income tax benefit (280,000) (200,000) (1,557,000)
Utility      
Current:      
Federal (1,000) 2,000 (1,000)
State 89,000 (78,000) 0
Deferred:      
Federal (171,000) (72,000) (981,000)
State (109,000) 45,000 (477,000)
Federal tax credits (2,000) (2,000) (2,000)
Total income tax benefit $ (194,000) $ (105,000) $ (1,461,000)
v3.25.4
INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Utility    
Deferred income tax assets:    
Tax carryforwards $ 9,199 $ 8,955
Compensation 127 86
GHG allowances 457 471
Wildfire-related claims 227 295
Operating lease liability 111 78
Transmission tower wireless license 251 251
Bad debt 137 127
Other 156 137
Total deferred income tax assets 10,665 10,400
Deferred income tax liabilities:    
Property-related basis difference 12,344 11,009
Regulatory balancing accounts 487 878
Income tax regulatory asset 1,723 1,335
Debt financing costs 353 390
Operating lease ROU asset 111 78
Environmental reserve 288 248
Other 91 94
Total deferred income tax liabilities 15,397 14,032
Total net deferred income tax liabilities 4,732 3,632
PG&E Corporation    
Deferred income tax assets:    
Tax carryforwards 9,752 9,429
Compensation 211 171
GHG allowances 457 471
Wildfire-related claims 227 295
Operating lease liability 111 78
Transmission tower wireless license 251 251
Bad debt 137 127
Other 127 140
Total deferred income tax assets 11,273 10,962
Deferred income tax liabilities:    
Property-related basis difference 12,357 11,021
Regulatory balancing accounts 487 878
Income tax regulatory asset 1,723 1,335
Debt financing costs 353 390
Operating lease ROU asset 111 78
Environmental reserve 288 248
Other 89 94
Total deferred income tax liabilities 15,408 14,044
Total net deferred income tax liabilities $ 4,135 $ 3,082
v3.25.4
INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Effective Income Tax Rate Reconciliation, Percent [Abstract]      
Federal statutory income tax rate 21.00% 21.00% 21.00%
State income tax (net of federal benefit) (1.80%) (2.00%) (57.90%)
Effect of regulatory treatment of fixed asset differences (34.20%) (28.90%) (62.40%)
Changes in valuation allowance 0.80% (0.90%) 0.70%
Nontaxable or nondeductible items 2.20% 0.80% 0.20%
Tax credits (1.10%) (1.00%) (3.40%)
Changes in unrecognized tax benefits 0.10% 2.10% 0.20%
Fire victim trust 0.00% 0.00% (126.90%)
Other, net 0.90% 0.10% 1.30%
Effective tax rate (12.10%) (8.80%) (227.20%)
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]      
Federal statutory income tax rate $ 486,000 $ 478,000 $ 144,000
State income tax (net of federal benefit) (41,000) (45,000) (397,000)
Effect of regulatory treatment of fixed asset differences (790,000) (657,000) (428,000)
Changes in valuation allowance 18,000 (20,000) 5,000
Nontaxable or nondeductible items 51,000 19,000 1,000
Tax credits (26,000) (22,000) (24,000)
Changes in unrecognized tax benefits 3,000 46,000 2,000
Fire victim trust 0 0 (869,000)
Other, net 19,000 1,000 9,000
Total income tax benefit $ (280,000) $ (200,000) $ (1,557,000)
Utility      
Effective Income Tax Rate Reconciliation, Percent [Abstract]      
Federal statutory income tax rate 21.00% 21.00% 21.00%
State income tax (net of federal benefit) (0.60%) (0.80%) (34.40%)
Effect of regulatory treatment of fixed asset differences (27.40%) (25.20%) (39.50%)
Changes in valuation allowance 0.00% 0.00% 0.10%
Nontaxable or nondeductible items 1.10% 0.40% 0.00%
Tax credits (0.90%) (0.90%) (2.20%)
Changes in unrecognized tax benefits 0.10% 1.90% 0.20%
Fire victim trust 0.00% 0.00% (80.20%)
Other, net 0.00% (0.40%) 0.20%
Effective tax rate (6.70%) (4.00%) (134.80%)
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]      
Federal statutory income tax rate $ 606,000 $ 547,000 $ 228,000
State income tax (net of federal benefit) (16,000) (22,000) (373,000)
Effect of regulatory treatment of fixed asset differences (790,000) (657,000) (428,000)
Changes in valuation allowance 0 0 1,000
Nontaxable or nondeductible items 30,000 12,000 0
Tax credits (26,000) (22,000) (24,000)
Changes in unrecognized tax benefits 3,000 49,000 2,000
Fire victim trust 0 0 (869,000)
Other, net (1,000) (12,000) 2,000
Total income tax benefit (194,000) (105,000) (1,461,000)
PG&E Corporation      
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]      
Total income tax benefit $ (86,000) $ (94,000) $ (96,000)
v3.25.4
INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Utility      
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]      
Balance, beginning of period $ 454 $ 616 $ 570
Additions for tax position taken during a prior year 5 0 1
Reductions for tax position taken during a prior year (7) (257) 0
Additions for tax position taken during the current year 665 95 45
Balance, end of period 1,117 454 616
PG&E Corporation      
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]      
Balance, beginning of period 454 616 570
Additions for tax position taken during a prior year 5 0 1
Reductions for tax position taken during a prior year (7) (257) 0
Additions for tax position taken during the current year 665 95 45
Balance, end of period $ 1,117 $ 454 $ 616
v3.25.4
INCOME TAXES (Narrative) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Investments, Owned, Federal Income Tax Note [Line Items]    
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year $ 102  
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
v3.25.4
INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Federal  
Operating Loss Carryforwards [Line Items]  
Tax credit carryforward $ 226
Federal | Pre-2018  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 3,307
Federal | Post-2017  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 34,957
State  
Operating Loss Carryforwards [Line Items]  
Net operating loss carryforward 34,143
Tax credit carryforward $ 167
v3.25.4
DERIVATIVES (Narrative) (Details)
Dec. 31, 2025
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]    
Derivative Asset, Statement of Financial Position [Extensible Enumeration] Regulatory assets Regulatory assets
v3.25.4
DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)
Dec. 31, 2025
MMBTU
MWh
Dec. 31, 2024
MWh
MMBTU
Natural Gas | Forwards, futures, and swaps    
Derivative [Line Items]    
Contract Volume 232,825,834 179,257,247
Natural Gas | Options    
Derivative [Line Items]    
Contract Volume 48,215,000 37,717,500
Electricity (MWh) | Forwards, futures, and swaps    
Derivative [Line Items]    
Contract Volume | MWh 7,196,942 8,576,078
Electricity (MWh) | Options    
Derivative [Line Items]    
Contract Volume 1,650,800 1,663,200
Electricity (MWh) | Congestion Revenue Rights    
Derivative [Line Items]    
Contract Volume | MWh 93,712,644 123,040,895
v3.25.4
DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Contract - Utility - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets $ 60 $ 100
Netting, Assets 0 0
Total Derivative Balance, Assets 60 100
Current assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets 165 186
Netting, Assets (46) (16)
Total Derivative Balance, Assets 119 170
Noncurrent assets – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Assets 170 233
Netting, Assets (6) 0
Total Derivative Balance, Assets 164 233
Current liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Liabilities (169) (152)
Netting, Liabilities 46 16
Total Derivative Balance, Liabilities (123) (136)
Noncurrent liabilities – other    
Derivatives And Hedging Activities [Line Items]    
Gross Derivative Balance, Liabilities (106) (167)
Netting, Liabilities 6 0
Total Derivative Balance, Liabilities $ (100) $ (167)
v3.25.4
FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Assets:    
Price risk management instruments, netting $ (52) $ (16)
TOTAL ASSETS 8,274 7,404
Liabilities:    
Price risk management instruments, netting (52) (16)
TOTAL LIABILITIES 223 303
Amount primarily related to deferred taxes on appreciation of investment value 881 747
Self-insurance investments    
Assets:    
TOTAL ASSETS 1,000  
Pacific Casualty Insurance Company, LLC    
Assets:    
TOTAL ASSETS 77  
Short-term investments    
Assets:    
Short-term investments 634 826
Fixed-income securities 0  
Self-insurance investments    
Assets:    
Short-term investments 1,120 905
TOTAL ASSETS 1,120 905
Nuclear decommissioning trusts    
Assets:    
Short-term investments 94 53
Global equity securities 2,433 2,228
Fixed-income securities 2,558 2,277
Price risk management instruments, netting   0
TOTAL ASSETS 5,111 4,580
Customer credit trust    
Assets:    
Short-term investments 111 1
Global equity securities 0 186
Fixed-income securities 693 190
TOTAL ASSETS 804 377
Rabbi trusts    
Assets:    
Short-term investments 115 107
Global equity securities   6
Fixed-income securities 5  
Life insurance contracts 65 66
TOTAL ASSETS 185 179
Long-term disability trust    
Assets:    
Short-term investments 10 4
TOTAL ASSETS 137 134
Total price risk management instruments    
Assets:    
Price risk management instruments, netting (52) (16)
Price risk management instruments, assets 283 403
Electricity    
Assets:    
Price risk management instruments, netting (6) (6)
Price risk management instruments, assets 296 403
Liabilities:    
Price risk management instruments, netting (6) (6)
Price risk management instruments, liabilities 204 279
Gas    
Assets:    
Price risk management instruments, netting (46) (10)
Price risk management instruments, assets (13) 0
Liabilities:    
Price risk management instruments, netting (46) (10)
Price risk management instruments, liabilities 19 24
Level 1    
Assets:    
TOTAL ASSETS 6,334 5,612
Liabilities:    
TOTAL LIABILITIES 0 0
Level 1 | Short-term investments    
Assets:    
Short-term investments 634 826
Fixed-income securities 0  
Level 1 | Self-insurance investments    
Assets:    
Short-term investments 1,120 905
TOTAL ASSETS 1,120 905
Level 1 | Nuclear decommissioning trusts    
Assets:    
Short-term investments 94 53
Global equity securities 2,433 2,228
Fixed-income securities 1,445 1,250
TOTAL ASSETS 3,972 3,531
Level 1 | Customer credit trust    
Assets:    
Short-term investments 111 1
Global equity securities 0 186
Fixed-income securities 367 46
TOTAL ASSETS 478 233
Level 1 | Rabbi trusts    
Assets:    
Short-term investments 115 107
Global equity securities   6
Fixed-income securities 5  
Life insurance contracts 0 0
TOTAL ASSETS 120 113
Level 1 | Long-term disability trust    
Assets:    
Short-term investments 10 4
TOTAL ASSETS 10 4
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 1,556 1,273
Liabilities:    
TOTAL LIABILITIES 145 71
Level 2 | Short-term investments    
Assets:    
Short-term investments 0 0
Fixed-income securities 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 1,113 1,027
TOTAL ASSETS 1,113 1,027
Level 2 | Customer credit trust    
Assets:    
Short-term investments 0 0
Global equity securities 0 0
Fixed-income securities 326 144
TOTAL ASSETS 326 144
Level 2 | Rabbi trusts    
Assets:    
Short-term investments 0 0
Global equity securities   0
Fixed-income securities 0  
Life insurance contracts 65 66
TOTAL ASSETS 65 66
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 52 36
Level 2 | Electricity    
Assets:    
Price risk management instruments, gross subject to netting 19 26
Liabilities:    
Price risk management instruments, gross subject to netting 80 37
Level 2 | Gas    
Assets:    
Price risk management instruments, gross subject to netting 33 10
Liabilities:    
Price risk management instruments, gross subject to netting 65 34
Level 3    
Assets:    
TOTAL ASSETS 283 383
Liabilities:    
TOTAL LIABILITIES 130 248
Level 3 | Short-term investments    
Assets:    
Short-term investments 0 0
Fixed-income securities 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
Fixed-income securities 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 283 383
Level 3 | Electricity    
Assets:    
Price risk management instruments, gross subject to netting 283 383
Liabilities:    
Price risk management instruments, gross subject to netting 130 248
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 26 22
Assets measured at NAV | Long-term disability trust    
Assets:    
Assets measured at NAV $ 127 $ 130
v3.25.4
FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
$ / shares
Dec. 31, 2024
USD ($)
$ / shares
Market approach | Congestion revenue rights    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ $ 252 $ 366
Liabilities | $ 83 121
Discounted cash flow | Power purchase agreements    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Assets | $ 31 17
Liabilities | $ $ 47 $ 127
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) (74) (951)
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 50,044
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) 11 0
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) 106 126
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) 53 47
v3.25.4
FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]    
Asset balance, beginning of period $ 127 $ 191
Included in regulatory assets and liabilities or balancing accounts 26 (64)
Asset balance, end of period $ 153 $ 127
v3.25.4
FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Carrying Amount    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument $ 5,360 $ 5,358
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 38,145 37,812
Level 2 | Fair Value    
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]    
Debt financial instrument 5,697 5,829
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 $ 35,565 $ 34,532
v3.25.4
FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Debt Securities, Available-for-sale [Line Items]    
Amount primarily related to deferred taxes on appreciation of investment value $ 881 $ 747
Nuclear decommissioning trusts    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 2,975 2,748
Total Unrealized Gains 2,188 1,927
Total Unrealized Losses (52) (95)
Total Fair Value 5,111 4,580
Nuclear decommissioning trusts | Short-term investments    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 94 54
Total Unrealized Gains 0 0
Total Unrealized Losses 0 (1)
Total Fair Value 94 53
Nuclear decommissioning trusts | Global equity securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 324 353
Total Unrealized Gains 2,140 1,907
Total Unrealized Losses (5) (10)
Total Fair Value 2,459 2,250
Nuclear decommissioning trusts | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 2,557 2,341
Total Unrealized Gains 48 20
Total Unrealized Losses (47) (84)
Total Fair Value 2,558 2,277
Customer credit trust    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 800 355
Total Unrealized Gains 5 29
Total Unrealized Losses (1) (7)
Total Fair Value 804 377
Customer credit trust | Short-term investments    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 111 1
Total Unrealized Gains 0 0
Total Unrealized Losses 0 0
Total Fair Value 111 1
Customer credit trust | Global equity securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 0 161
Total Unrealized Gains 0 28
Total Unrealized Losses 0 (3)
Total Fair Value 0 186
Customer credit trust | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Amortized Cost 689 193
Total Unrealized Gains 5 1
Total Unrealized Losses (1) (4)
Total Fair Value $ 693 $ 190
v3.25.4
FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Nuclear decommissioning trusts    
Debt Securities, Available-for-sale [Line Items]    
Total maturities of fixed-income securities $ 5,111 $ 4,580
Nuclear decommissioning trusts | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Less than 1 year 95  
1–5 years 822  
5–10 years 564  
More than 10 years 1,077  
Total maturities of fixed-income securities 2,558 2,277
Customer credit trust    
Debt Securities, Available-for-sale [Line Items]    
Total maturities of fixed-income securities 804 377
Customer credit trust | Fixed-income securities    
Debt Securities, Available-for-sale [Line Items]    
Less than 1 year 290  
1–5 years 107  
5–10 years 49  
More than 10 years 247  
Total maturities of fixed-income securities $ 693 $ 190
v3.25.4
FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Proceeds from sales and maturities of nuclear decommissioning trust investments $ 1,952 $ 1,980 $ 2,235
Nuclear decommissioning trusts      
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Proceeds from sales and maturities of nuclear decommissioning trust investments 1,952 1,980 2,235
Gross realized gains on securities 213 255 80
Gross realized losses on securities (25) (63) (74)
Customer credit trust      
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]      
Proceeds from sales and maturities of nuclear decommissioning trust investments 435 398 556
Gross realized gains on securities 131 10 23
Gross realized losses on securities $ (20) $ (8) $ (19)
v3.25.4
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Funded Status:      
Noncurrent liability $ (549) $ (808)  
Pension Plan      
Change in plan assets:      
Fair value of plan assets at beginning of year 16,767 17,211  
Actual return on plan assets 1,779 218  
Company contributions 337 337  
Benefits and expenses paid (1,020) (999)  
Fair value of plan assets at end of year 17,863 16,767 $ 17,211
Change in benefit obligation:      
Benefit obligation at beginning of year 17,585 17,697  
Service cost for benefits earned 424 396 379
Interest cost 1,007 916 913
Actuarial loss/(gain) 427 (424)  
Benefits and expenses paid (1,020) (1,000)  
Benefit obligation at end of year 18,423 17,585 17,697
Funded Status:      
Current liability (10) (10)  
Noncurrent liability (550) (808)  
Net (liability) asset at end of year (560) (818)  
Accumulated benefit obligation 16,500 15,800  
PBOP Plans      
Change in plan assets:      
Fair value of plan assets at beginning of year 2,471 2,499  
Actual return on plan assets 200 74  
Company contributions 7 5  
Plan participant contribution 91 84  
Benefits and expenses paid (196) (191)  
Fair value of plan assets at end of year 2,573 2,471 2,499
Change in benefit obligation:      
Benefit obligation at beginning of year 1,279 1,377  
Service cost for benefits earned 38 41 38
Interest cost 73 71 73
Actuarial loss/(gain) 125 (123)  
Benefits and expenses paid (182) (174)  
Federal subsidy on benefits paid 4 3  
Plan participant contributions 91 84  
Benefit obligation at end of year 1,428 1,279 $ 1,377
Funded Status:      
Noncurrent asset 1,144 1,192  
Noncurrent liability 0 0  
Net (liability) asset at end of year 1,144 1,192  
PBOP Plans | Postretirement Life Insurance Plan      
Change in plan assets:      
Fair value of plan assets at beginning of year 296    
Fair value of plan assets at end of year 322 296  
Change in benefit obligation:      
Benefit obligation at beginning of year 261    
Benefit obligation at end of year $ 274 $ 261  
v3.25.4
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Service cost for benefits earned $ 424 $ 396 $ 379
Interest cost 1,007 916 913
Expected return on plan assets (1,053) (1,014) (981)
Amortization of prior service cost (3) (3) (4)
Amortization of net actuarial gain (loss) 2 1 1
Net periodic benefit cost 377 296 308
Less: transfer to regulatory account (40) 39 25
Total expense recognized 337 335 333
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Service cost for benefits earned 38 41 38
Interest cost 73 71 73
Expected return on plan assets (150) (139) (132)
Amortization of prior service cost 3 3 3
Amortization of net actuarial gain (loss) (23) (23) (19)
Net periodic benefit cost $ (59) $ (47) $ (37)
v3.25.4
EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]      
Expected return on plan assets 5.70%    
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 5.58% 5.76% 5.21%
Rate of future compensation increases 4.80% 4.80% 3.80%
Expected return on plan assets 7.00% 6.40% 6.00%
Interest crediting rate for cash balance plan 4.23% 4.41% 3.86%
PBOP Plans | Minimum      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 5.51% 5.71% 5.18%
Expected return on plan assets 4.30% 3.90% 3.70%
PBOP Plans | Maximum      
Defined Benefit Plan Disclosure [Line Items]      
Discount rate 5.60% 5.76% 5.22%
Expected return on plan assets 7.20% 7.20% 7.00%
v3.25.4
EMPLOYEE BENEFIT PLANS (Narrative) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
bond
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Defined Benefit Plan Disclosure [Line Items]      
Assumed health care cost trend rate 7.00%    
Ultimate trend rate 4.50%    
Assumed return 7.00%    
10 year actual rate of return 5.70%    
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | bond 831    
Retirement savings plan expense $ 194 $ 175 $ 158
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
10 year actual rate of return 7.00% 6.40% 6.00%
Company contributions $ 337 $ 337  
Expected employer contribution next year 327    
Long-term Disability Trusts      
Defined Benefit Plan Disclosure [Line Items]      
Company contributions 31    
Expected employer contribution next year 31    
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Company contributions $ 7 $ 5  
v3.25.4
EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)
Dec. 31, 2026
Dec. 31, 2025
Dec. 31, 2024
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   100.00% 100.00%
Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   26.00% 26.00%
Pension Plan | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   1.00% 1.00%
Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   8.00% 8.00%
Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   65.00% 65.00%
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   100.00% 100.00%
PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   30.00% 29.00%
PBOP Plans | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   0.00% 0.00%
PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   3.00% 3.00%
PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation   67.00% 68.00%
Forecast | Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 100.00%    
Forecast | Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 28.00%    
Forecast | Pension Plan | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 1.00%    
Forecast | Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 6.00%    
Forecast | Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 65.00%    
Forecast | PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 100.00%    
Forecast | PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 14.00%    
Forecast | PBOP Plans | Absolute return      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 0.00%    
Forecast | PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 3.00%    
Forecast | PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total target asset allocation 83.00%    
v3.25.4
EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value $ 20,436 $ 19,238  
Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV 12 16 $ 13
Pension Plan      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 17,863 16,767  
Assets measured at NAV 17,863 16,767 17,211
Pension Plan | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 482 173  
Pension Plan | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,445 1,310  
Pension Plan | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2 437  
Pension Plan | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 8,882 8,563  
Pension Plan | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 3,889 4,053  
Pension Plan | Level 1 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 452 126  
Pension Plan | Level 1 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,445 1,310  
Pension Plan | Level 1 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2 437  
Pension Plan | Level 1 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,990 2,180  
Pension Plan | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 6,910 6,414  
Pension Plan | Level 2 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 30 47  
Pension Plan | Level 2 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 2 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 2 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 6,880 6,367  
Pension Plan | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 12 16  
Pension Plan | Level 3 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
Pension Plan | Level 3 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 12 16  
Pension Plan | Assets measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV 7,052 6,284  
PBOP Plans      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2,573 2,471  
Assets measured at NAV 2,573 2,471 $ 2,499
PBOP Plans | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 546 27  
PBOP Plans | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2 60  
PBOP Plans | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 20  
PBOP Plans | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,079 1,183  
PBOP Plans | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 1,066 538  
PBOP Plans | Level 1 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 546 27  
PBOP Plans | Level 1 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 2 60  
PBOP Plans | Level 1 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 20  
PBOP Plans | Level 1 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 518 431  
PBOP Plans | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 561 751  
PBOP Plans | Level 2 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 2 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 561 751  
PBOP Plans | Level 3      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 1  
PBOP Plans | Level 3 | Short-term investments      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Global equity securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Real assets      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 0  
PBOP Plans | Level 3 | Fixed-income securities      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets at fair value 0 1  
PBOP Plans | Assets measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Assets measured at NAV $ 946 $ 1,181  
v3.25.4
EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]    
Fair value of plan assets at beginning of year $ 16 $ 13
Actual return on plan assets:    
Relating to assets still held at the reporting date 7 9
Relating to assets sold during the period (7) (9)
Purchases, issuances, sales, and settlements:    
Purchases 6 14
Settlements (10) (11)
Fair value of plan assets at end of year $ 12 $ 16
v3.25.4
EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Pension Plan  
Defined Benefit Plan Disclosure [Line Items]  
2026 $ 993
2027 1,082
2028 1,110
2029 1,136
2030 1,161
2031-2035 6,159
PBOP Plans  
Defined Benefit Plan Disclosure [Line Items]  
2026 84
2027 86
2028 90
2029 93
2030 96
2031-2035 523
Federal Subsidy  
Defined Benefit Plan Disclosure [Line Items]  
2026 (1)
2027 (1)
2028 (1)
2029 (1)
2030 (1)
2031-2035 $ (6)
v3.25.4
WILDFIRE-RELATED CONTINGENCIES - Litigation Payments (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Loss Contingencies [Line Items]  
Litigation payment $ 3,302
2019 Kincade Fire  
Loss Contingencies [Line Items]  
Litigation payment 1,287
2021 Dixie fire  
Loss Contingencies [Line Items]  
Litigation payment 1,908
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Litigation payment $ 107
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire, 2021 Dixie Fire and 2022 Mosquito Fire) (Details)
people in Millions, $ in Millions
 3 Months Ended 12 Months Ended
Jul. 13, 2021
USD ($)
a
structure
injury
Nov. 04, 2019
people
Dec. 31, 2025
USD ($)
Jun. 30, 2025
USD ($)
Mar. 31, 2025
USD ($)
Dec. 31, 2025
USD ($)
Feb. 04, 2026
notice
claimHolder
plaintiff
complaint
company
Dec. 31, 2024
USD ($)
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
Number of people part of mandatory evacuation order | people   0.2                
Loss contingency liability     $ 1,325     $ 1,325   $ 1,225    
Potential loss contingency       $ 50 $ 50          
Insurance receivable fully collected     430     430        
Liability insurance coverage, insurance receivable. fully recoveries     111     111        
2019 Kincade Fire | Subsequent Event                    
Loss Contingencies [Line Items]                    
Number of complaints (complaint) | complaint             135      
Number of plaintiffs represented by complaints | plaintiff             3,014      
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     2,150   1,925    
Loss contingency accrual, period increase (decrease)     25     225        
Loss contingency, costs incurred $ 650                  
Insurance receivable     521     521        
Probable of recovery           2,303        
2021 Dixie fire | Subsequent Event                    
Loss Contingencies [Line Items]                    
Number of complaints (complaint) | claimHolder             189      
Number of plaintiffs represented by complaints | claimHolder             9,034      
2021 Dixie fire | Wildfire Fund                    
Loss Contingencies [Line Items]                    
Probable of recovery           1,150        
Probable of recovery received           851        
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           535        
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                  
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     350     350   $ 100    
Number of residential structures destroyed (structure) | structure                 44  
Number of detached structures destroyed (structure) | structure                 40  
Loss contingency accrual, period increase (decrease)     100     250        
Insurance receivable     $ 363     363        
Probable of recovery           424        
Percentage of fire contained                 100.00%  
2022 Mosquito fire | Subsequent Event                    
Loss Contingencies [Line Items]                    
Number of complaints (complaint) | complaint             35      
Number of plaintiffs represented by complaints | notice             2,939      
Number of public entities who files complaints | company             6      
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        
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
2019 Kincade Fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance $ 267
Accrued Losses 100
Payments (329)
Loss accrual, ending balance 38
2021 Dixie fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance 567
Accrued Losses 225
Payments (549)
Loss accrual, ending balance 243
2022 Mosquito fire  
Loss Contingency Accrual [Roll Forward]  
Loss accrual, beginning balance 82
Accrued Losses 250
Payments (89)
Loss accrual, ending balance $ 243
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery $ 2,303
Probable of recovery, legal costs 148
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 424
Probable of recovery, legal costs 73
Insurance | 2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery 521
Insurance | 2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 363
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 535
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
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Self-Insurance) (Details) - CPUC
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Loss Contingencies [Line Items]  
Self insurance amount $ 1,000
Self insurance deductible, percent 0.05
Self insurance deductible maximum $ 50
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Insurance Receivable [Roll Forward]  
Insurance receivable, beginning balance $ 117
Accrued insurance recoveries 267
Reimbursements (102)
Insurance receivable, ending balance 282
2021 Dixie fire  
Insurance Receivable [Roll Forward]  
Insurance receivable 521
Insurance receivable, beginning balance 27
Accrued insurance recoveries (6)
Reimbursements (20)
Insurance receivable, ending balance 1
2022 Mosquito fire  
Insurance Receivable [Roll Forward]  
Insurance receivable 363
Insurance receivable, beginning balance 90
Accrued insurance recoveries 273
Reimbursements (82)
Insurance receivable, ending balance $ 281
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
2021 Dixie fire  
Loss Contingencies [Line Items]  
Probable of recovery $ 2,303
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 535
2022 Mosquito fire  
Loss Contingencies [Line Items]  
Probable of recovery 424
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
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($)
$ in Millions
 12 Months Ended
Aug. 23, 2019
Dec. 31, 2025
Dec. 31, 2024
Loss Contingencies [Line Items]      
Disallowance cap, transmission and distribution equity rate base   $ 4,700  
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   $ 282 $ 117
2021 Dixie fire      
Loss Contingencies [Line Items]      
Insurance receivable   1 $ 27
2021 Dixie fire | Noncurrent assets – other      
Loss Contingencies [Line Items]      
Insurance receivable   295  
2021 Dixie fire | Noncurrent assets – other | Utility      
Loss Contingencies [Line Items]      
Insurance receivable   $ 4  
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Changes in Accrued Wildfire Fund Recoveries) (Details) - 2021 Dixie fire
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Loss Contingency Accrual [Roll Forward]  
Wildfire fund receivable, beginning balance $ 756
Accrued Wildfire Fund recoveries 225
Claims paid by Wildfire Fund (682)
Wildfire fund receivable, ending balance $ 299
v3.25.4
WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Securities Litigation and Claims in District Court) (Details) - Wildfire-Related Class Action
$ in Millions
Jan. 10, 2026
USD ($)
Dec. 31, 2025
USD ($)
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  
Percentage of common stock owned, Fire Victim Trust if common issues additional shares   22.19%    
Subsequent Event        
Loss Contingencies [Line Items]        
Loss contingency, damages sought $ 100      
v3.25.4
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
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]    
Accrued legal liabilities $ 151 $ 74
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]    
Topock natural gas compressor station $ 315 $ 294
Hinkley natural gas compressor station 99 97
Former MGP sites owned by the Utility or third parties 715 782
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 71 76
Fossil fuel-fired generation facilities and sites 17 18
Total environmental remediation liability $ 1,217 $ 1,267
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details)
$ in Billions
Dec. 31, 2025
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
Amount of environmental loss accrual expected to be recovered $ 1.0
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Contingencies) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Site Contingency [Line Items]    
Topock natural gas compressor station $ 315 $ 294
Hinkley natural gas compressor station 99 97
Former MGP sites owned by the Utility or third parties 715 782
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 71 76
Fossil fuel-fired generation facilities and sites $ 17 $ 18
Utility    
Site Contingency [Line Items]    
Remediation cost recovery percentage 90.00%  
Maximum    
Site Contingency [Line Items]    
Topock natural gas compressor station $ 518  
Hinkley natural gas compressor station 221  
Former MGP sites owned by the Utility or third parties 1,292  
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 146  
Fossil fuel-fired generation facilities and sites $ 32  
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Purchase Commitments) (Details)
 12 Months Ended
Dec. 31, 2025
USD ($)
nuclearGeneratingUnit
Long-term Purchase Commitment [Line Items]  
Number of nuclear generating units (nuclear generating unit) | nuclearGeneratingUnit 2
Maximum total payment incurred per event under the loss sharing program $ 500,000,000
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance  
Long-term Purchase Commitment [Line Items]  
Insurance coverage, loss 400,000,000
Humboldt Bay Unit  
Long-term Purchase Commitment [Line Items]  
Amount of property damage coverage provided by NEIL 50,000,000
Amount of liability insurance for Humboldt Bay Unit 3 53,000,000
Diablo Canyon  
Long-term Purchase Commitment [Line Items]  
Maximum public liability per nuclear incident under Price-Anderson Act 16,300,000,000
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act 500,000,000
Maximum annual payment incurred per event under the loss sharing program 332,000,000
Maximum annual payment incurred per event under the loss sharing program $ 49,000,000
Period for inflation adjustment 5 years
Nuclear Incident  
Long-term Purchase Commitment [Line Items]  
Amount of property damage and business interruption coverage $ 3,200,000,000
Nuclear Incident | Humboldt Bay Unit  
Long-term Purchase Commitment [Line Items]  
Amount of indemnification from the nuclear regulatory commission for public liability arising from nuclear incidents 500,000,000
Non-Nuclear Incident  
Long-term Purchase Commitment [Line Items]  
Amount of property damage and business interruption coverage 2,500,000,000
European Mutual Association for Nuclear Insurance  
Long-term Purchase Commitment [Line Items]  
Full insurance policy limit 200,000,000
Nuclear Electric Insurance Limited  
Long-term Purchase Commitment [Line Items]  
Potential premium obligation $ 43,000,000
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Purchase Commitments) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Long-term Purchase Commitment [Line Items]  
2026 $ 3,817
2027 3,283
2028 3,045
2029 2,867
2030 2,406
Thereafter 17,182
Total purchase commitments 32,600
Renewable Energy  
Long-term Purchase Commitment [Line Items]  
2026 1,937
2027 1,921
2028 1,903
2029 1,858
2030 1,852
Thereafter 12,828
Total purchase commitments 22,299
Conventional Energy  
Long-term Purchase Commitment [Line Items]  
2026 1,058
2027 1,035
2028 989
2029 905
2030 510
Thereafter 4,315
Total purchase commitments 8,812
Natural Gas  
Long-term Purchase Commitment [Line Items]  
2026 544
2027 193
2028 106
2029 98
2030 42
Thereafter 34
Total purchase commitments 1,017
Other  
Long-term Purchase Commitment [Line Items]  
2026 278
2027 134
2028 47
2029 6
2030 2
Thereafter 5
Total purchase commitments $ 472
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Third-Party Power Purchase Agreements and Other Agreements) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Power Purchases and Electric Capacity      
Third-Party Power Purchase Agreements [Line Items]      
Costs incurred for power purchases and electric capacity $ 2,000 $ 2,100 $ 2,400
Nuclear Fuel      
Third-Party Power Purchase Agreements [Line Items]      
Payments for nuclear fuel 134 294 180
Gas Contracts      
Third-Party Power Purchase Agreements [Line Items]      
Cost of goods $ 1,000 $ 800 $ 2,500
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Other Commitments) (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Commitments and Contingencies Disclosure [Abstract]  
2026 $ 82
2027 51
2028 41
2029 39
2030 13
Thereafter 65
Total minimum payments $ 291
v3.25.4
OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2040
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating Leased Assets [Line Items]        
Payments for other commitments   $ 63 $ 105 $ 106
SB 901 securitization | Secured Debt | Forecast        
Operating Leased Assets [Line Items]        
Shareholder contribution amount $ 775      
Percentage surplus shared 25.00%      
Minimum        
Operating Leased Assets [Line Items]        
Extension option for operating leases   1 year    
Maximum        
Operating Leased Assets [Line Items]        
Extension option for operating leases   5 years    
v3.25.4
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Condensed Income Statements, Captions [Line Items]      
Operating expenses $ (20,186) $ (19,960) $ (21,757)
Interest income 520 604 606
Interest expense (3,028) (3,051) (2,850)
Other income, net 182 300 272
Income tax benefit (280) (200) (1,557)
Net Income 2,703 2,512 2,256
Preferred stock dividend requirement 110 37 14
Income Available for Common Shareholders 2,593 2,475 2,242
Income Available for Common Shareholders 2,593 2,475 2,242
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations, tax 4 3 6
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively) (11) (7) (16)
Net unrealized gain on available-for-sale securities 2 0 3
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $3, respectively) 5 1 8
Total other comprehensive income (loss) $ (6) $ (6) $ (8)
Weighted Average Common Shares Outstanding, Basic (in shares) 2,197 2,141 2,064
Weighted average common share outstanding, diluted (in shares) 2,202 2,147 2,138
Net Earnings Per Common Share, Basic (in dollars per share) $ 1.18 $ 1.16 $ 1.09
Net Earnings Per Common Share, Diluted (in dollars per share) $ 1.18 $ 1.15 $ 1.05
PG&E Corporation      
Condensed Income Statements, Captions [Line Items]      
Operating expenses $ (207) $ (167) $ (165)
Interest income 11 15 13
Interest expense (315) (270) (365)
Other income, net (145) (17) (21)
Equity in earnings of subsidiaries 3,065 2,697 2,530
Income Before Income Taxes 2,603 2,404 2,146
Income tax benefit (86) (94) (96)
Net Income 2,689 2,498 2,242
Preferred stock dividend requirement 96 23 0
Income Available for Common Shareholders 2,593 2,475 2,242
Income Available for Common Shareholders 2,593 2,475 2,242
Other Comprehensive Income (Loss)      
Pension and other postretirement benefit plans obligations, tax 0 3 6
Pension and other postretirement benefit plans obligations (net of taxes of $4, $3, and $6, respectively) (3) (7) (16)
Net unrealized gain on available-for-sale securities 0 0 0
Net unrealized gain (losses) on available-for-sale securities (net of taxes of $2, $0, and $3, respectively) 0 1 0
Total other comprehensive income (loss) (3) (6) (16)
Comprehensive Income $ 2,590 $ 2,469 $ 2,226
Weighted Average Common Shares Outstanding, Basic (in shares) 2,197 2,141 2,064
Weighted average common share outstanding, diluted (in shares) 2,202 2,147 2,138
Net Earnings Per Common Share, Basic (in dollars per share) $ 1.18 $ 1.16 $ 1.09
Net Earnings Per Common Share, Diluted (in dollars per share) $ 1.18 $ 1.15 $ 1.05
PG&E Corporation | Administrative service revenue      
Condensed Income Statements, Captions [Line Items]      
Administrative service revenue $ 194 $ 146 $ 154
v3.25.4
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current Assets      
Cash and cash equivalents $ 713 $ 940 $ 635
Restricted cash and cash equivalents 259 273 297
Total current assets 15,830 17,216  
Other Noncurrent Assets      
TOTAL ASSETS 141,611 133,660  
Current Liabilities      
Other current liabilities 4,025 3,658  
Total current liabilities 16,300 16,330  
Noncurrent Liabilities      
Long-term debt 57,387 53,569  
Other noncurrent liabilities 4,459 4,166  
Total noncurrent liabilities 92,519 86,929  
Shareholders’ Equity      
Mandatory convertible preferred stock 1,579 1,579  
Common stock 31,636 31,555  
Reinvested earnings (650) (2,966)  
Accumulated other comprehensive loss (25) (19)  
Total shareholders’ equity 32,540 30,149  
TOTAL LIABILITIES AND EQUITY 141,611 133,660  
PG&E Corporation      
Current Assets      
Cash and cash equivalents 360 235 192
Restricted cash and cash equivalents 1 1 $ 3
Advances to affiliates 54 13  
Income taxes receivable 39 2  
Total current assets 454 251  
Other Noncurrent Assets      
Investments in subsidiaries 45,110 42,829  
Other investments 182 175  
Deferred income taxes 682 633  
Total other noncurrent assets 45,974 43,637  
TOTAL ASSETS 46,428 43,888  
Current Liabilities      
Accounts payable – other 146 36  
Income taxes payable 0 1  
Other current liabilities 444 420  
Total current liabilities 590 457  
Noncurrent Liabilities      
Long-term debt 5,622 5,612  
Other noncurrent liabilities 151 141  
Total noncurrent liabilities 5,773 5,753  
Shareholders’ Equity      
Mandatory convertible preferred stock 1,579 1,579  
Common stock 39,168 39,086  
Reinvested earnings (650) (2,966)  
Accumulated other comprehensive loss (32) (21)  
Total shareholders’ equity 40,065 37,678  
TOTAL LIABILITIES AND EQUITY $ 46,428 $ 43,888  
v3.25.4
SCHEDULE I – CONSOLIDATED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Flows from Operating Activities      
Net Income $ 2,703 $ 2,512 $ 2,256
Adjustments to reconcile net income to net cash provided by operating activities:      
Deferred income taxes and tax credits, net 1,058 1,098 (765)
Net cash provided by operating activities 8,716 8,035 4,747
Cash Flows from Investing Activities      
Net cash used in investing activities (12,316) (11,375) (9,162)
Cash Flows From Financing Activities:      
Repayments under term loan credit facilities (1,465) (10,122) (10,540)
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $0, and $27 at respective dates 0 0 2,123
Premium, discount, and issuance costs on proceeds from long-term debt 38 5 67
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $38, $5, and $67 at respective dates 4,962 4,495 5,483
Common stock issued 0 1,128 0
Mandatory convertible preferred stock dividends paid (97) 0 0
Other (87) (59) (17)
Net cash provided by financing activities 3,359 3,621 4,400
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents (241) 281 (15)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 1,213 932 947
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 972 1,213 932
Less: Restricted cash and restricted cash equivalents (259) (273) (297)
Cash and cash equivalents at December 31 713 940 635
Supplemental disclosures of cash flow information      
Interest, net of amounts capitalized (2,665) (2,421) (2,286)
Noncash Investing and Financing Items [Abstract]      
Changes to PG&E Corporation common stock and treasury stock in connection with the share exchange with the Fire Victim Trust 0 0 (2,517)
Convertible Notes due 2027      
Cash Flows From Financing Activities:      
Premium, discount, and issuance costs on proceeds from long-term debt 0 0 27
Series A Preferred Stock      
Cash Flows From Financing Activities:      
Mandatory convertible preferred stock issued 0 1,579 0
Noncash Investing and Financing Items [Abstract]      
Dividends declared but not yet paid 23 23 0
PG&E Corporation      
Cash Flows from Operating Activities      
Net Income 2,689 2,498 2,242
Adjustments to reconcile net income to net cash provided by operating activities:      
Stock-based compensation amortization 82 53 4
Equity in earnings of subsidiaries (3,065) (2,699) (2,530)
Deferred income taxes and tax credits, net (49) (94) (116)
Current income taxes payable (33) 0 9
Other 55 9 40
Net cash provided by operating activities (321) (233) (351)
Cash Flows from Investing Activities      
Investment in subsidiaries (1,575) (5,360) (1,290)
Dividends received from subsidiaries [1] 2,350 2,025 1,775
Net cash used in investing activities 775 (3,335) 485
Cash Flows From Financing Activities:      
Repayments under term loan credit facilities 0 (500) (2,181)
Proceeds from issuance of convertible notes, net of discount and issuance costs of $0, $0, and $27 at respective dates 0 0 2,123
Premium, discount, and issuance costs on proceeds from long-term debt 0 0 27
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $38, $5, and $67 at respective dates 0 1,496 0
Common stock issued 0 1,128 0
Mandatory convertible preferred stock issued 0 1,579 0
Mandatory convertible preferred stock dividends paid (97) 0 0
Common stock dividends paid (220) (86) 0
Other (12) (8) (6)
Net cash provided by financing activities (329) 3,609 (64)
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents 125 41 70
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1 236 195 125
Cash, cash equivalents, restricted cash, and restricted cash equivalents at December 31 361 236 195
Less: Restricted cash and restricted cash equivalents (1) (1) (3)
Cash and cash equivalents at December 31 360 235 192
Supplemental disclosures of cash flow information      
Interest, net of amounts capitalized (306) (215) (309)
Noncash Investing and Financing Items [Abstract]      
Changes to PG&E Corporation common stock and treasury stock in connection with the share exchange with the Fire Victim Trust 0 0 (2,517)
Dividends declared but not yet paid 111 55 21
PG&E Corporation | Convertible Notes due 2027      
Cash Flows From Financing Activities:      
Premium, discount, and issuance costs on proceeds from long-term debt 0 4 0
PG&E Corporation | Series A Preferred Stock      
Noncash Investing and Financing Items [Abstract]      
Dividends declared but not yet paid $ 23 $ 23 $ 0
[1] Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow.
v3.25.4
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Beginning of Period $ 418 $ 445 $ 166
Charged to Costs and Expenses 362 312 624
Charged to Other Accounts 0 0 0
Deductions 372 339 345
Balance at End of Period $ 408 $ 418 $ 445