PG&E (PCG) 10-Q 29 Apr 21 2021 Q1 Quarterly report Financial data

Cover

Cover - shares	3 Months Ended
	Mar. 31, 2021	Apr. 26, 2021
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	1-12609
Entity Registrant Name	PG&E CORP
Entity Incorporation, State or Country Code	CA
Entity Tax Identification Number	94-3234914
Entity Address, Address Line One	77 Beale Street
Entity Address, Address Line Two	P.O. Box 770000
Entity Address, City or Town	San Francisco,
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	94177
City Area Code	415
Local Phone Number	973-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		1,985,105,703
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001004980
Current Fiscal Year End Date	--12-31
Pacific Gas & Electric Co (Utility)
Entity Information [Line Items]
Entity File Number	1-2348
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Incorporation, State or Country Code	CA
Entity Tax Identification Number	94-0742640
Entity Address, Address Line One	77 Beale Street
Entity Address, Address Line Two	P.O. Box 770000
Entity Address, City or Town	San Francisco,
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	94177
City Area Code	415
Local Phone Number	973-7000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		264,374,809
Amendment Flag	false
Entity Central Index Key	0000075488
The New York Stock Exchange | Common stock, no par value
Entity Information [Line Items]
Title of 12(b) Security	Common stock, no par value
Trading Symbol	PCG
Security Exchange Name	NYSE
The New York Stock Exchange | Equity Units
Entity Information [Line Items]
Title of 12(b) Security	Equity Units
Trading Symbol	PCGU
Security Exchange Name	NYSE
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% series A redeemable
Trading Symbol	PCG-PE
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% redeemable
Trading Symbol	PCG-PD
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable
Entity Information [Line Items]
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
Entity Information [Line Items]
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
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable
Trading Symbol	PCG-PI
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable
Entity Information [Line Items]
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
Entity Information [Line Items]
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
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% nonredeemable
Trading Symbol	PCG-PC
Security Exchange Name	NYSEAMER

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating Revenues
Total operating revenues	$ 4,716	$ 4,306
Operating Expenses
Operating and maintenance	2,336	1,967
Wildfire-related claims, net of insurance recoveries	172	0
Wildfire Fund expense	119	0
Depreciation, amortization, and decommissioning	888	855
Total operating expenses	4,412	3,651
Operating Income	304	655
Interest income	2	16
Interest expense	(408)	(254)
Other income, net	127	97
Reorganization items, net	0	(176)
Income Before Income Taxes	25	338
Income tax benefit	(98)	(36)
Net Income	123	374
Preferred stock dividend requirement of subsidiary	3	3
Income Available for Common Shareholders	$ 120	$ 371
Weighted Average Common Shares Outstanding, Basic (in shares)	1,985	529
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,131	648
Net Earnings Per Common Share, Basic (in dollars per share)	$ 0.06	$ 0.70
Net Earnings Per Common Share, Diluted (in dollars per share)	$ 0.06	$ 0.57
Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	$ 4,716	$ 4,306
Operating Expenses
Operating and maintenance	2,331	1,965
Wildfire-related claims, net of insurance recoveries	172	0
Wildfire Fund expense	119	0
Depreciation, amortization, and decommissioning	888	855
Total operating expenses	4,407	3,649
Operating Income	309	657
Interest income	2	16
Interest expense	(348)	(252)
Other income, net	133	93
Reorganization items, net	(2)	(93)
Income Before Income Taxes	94	421
Income tax benefit	(83)	(30)
Net Income	177	451
Preferred stock dividend requirement of subsidiary	3	3
Income Available for Common Shareholders	174	448
Electric
Operating Revenues
Total operating revenues	3,395	3,040
Operating Expenses
Cost of goods	590	545
Electric | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	3,395	3,040
Operating Expenses
Cost of goods	590	545
Natural gas
Operating Revenues
Total operating revenues	1,321	1,266
Operating Expenses
Cost of goods	307	284
Natural gas | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	1,321	1,266
Operating Expenses
Cost of goods	$ 307	$ 284

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Net income	$ 123	$ 374
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	1	0
Total other comprehensive income	1	0
Comprehensive Income	124	374
Preferred stock dividend requirement of subsidiary	3	3
Comprehensive Income Available for Common Shareholders	121	371
Pacific Gas & Electric Co (Utility)
Net income	177	451
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, respectively)	0	0
Total other comprehensive income	0	0
Comprehensive Income	$ 177	$ 451

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0
Pacific Gas & Electric Co (Utility)
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 229	$ 484
Restricted cash	29	143
Accounts receivable:
Customers (net of allowance for doubtful accounts of $212 million and $146 million at respective dates) (includes $1.61 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $211 million and $143 million at respective dates)	1,835	1,883
Accrued unbilled revenue (includes $897 million and $959 million related to VIEs at respective dates)	991	1,083
Regulatory balancing accounts	2,249	2,001
Other	1,157	1,172
Regulatory assets	410	410
Inventories:
Gas stored underground and fuel oil	17	95
Materials and supplies	533	533
Wildfire Fund asset	464	464
Other	1,153	1,334
Total current assets	9,067	9,602
Property, Plant, and Equipment
Electric	68,054	66,982
Gas	24,548	24,135
Construction work in progress	2,895	2,757
Other	25	20
Total property, plant, and equipment	95,522	93,894
Accumulated depreciation	(28,261)	(27,758)
Net property, plant, and equipment	67,261	66,136
Other Noncurrent Assets
Regulatory assets	9,159	8,978
Nuclear decommissioning trusts	3,592	3,538
Operating lease right of use asset	1,659	1,741
Wildfire Fund asset	5,700	5,816
Income taxes receivable	68	67
Other	2,052	1,978
Total other noncurrent assets	22,230	22,118
TOTAL ASSETS	98,558	97,856
Current Liabilities
Short-term borrowings	1,448	3,547
Long-term debt, classified as current	1,522	28
Accounts payable:
Trade creditors	2,141	2,402
Regulatory balancing accounts	1,368	1,245
Other	708	580
Operating lease liabilities	534	533
Interest payable	290	498
Disputed claims and customer refunds	244	242
Wildfire-related claims	1,692	2,250
Other	2,270	2,256
Total current liabilities	12,217	13,581
Noncurrent Liabilities
Long-term debt (includes $650 million and $1.0 billion related to VIEs at respective dates)	37,801	37,288
Regulatory liabilities	11,204	10,424
Pension and other post-retirement benefits	2,406	2,444
Asset retirement obligations	6,494	6,412
Deferred income taxes	1,468	1,398
Operating lease liabilities	1,125	1,208
Other	4,464	3,848
Total noncurrent liabilities	64,962	63,022
Shareholders’ Equity
Common stock	30,226	30,224
Reinvested earnings	(9,073)	(9,196)
Accumulated other comprehensive loss	(26)	(27)
Total shareholders’ equity	21,127	21,001
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	21,379	21,253
TOTAL LIABILITIES AND EQUITY	98,558	97,856
Pacific Gas & Electric Co (Utility)
Current Assets
Cash and cash equivalents	127	261
Restricted cash	29	143
Accounts receivable:
Customers (net of allowance for doubtful accounts of $212 million and $146 million at respective dates) (includes $1.61 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $211 million and $143 million at respective dates)	1,835	1,883
Accrued unbilled revenue (includes $897 million and $959 million related to VIEs at respective dates)	991	1,083
Regulatory balancing accounts	2,249	2,001
Other	1,161	1,180
Regulatory assets	410	410
Inventories:
Gas stored underground and fuel oil	17	95
Materials and supplies	533	533
Wildfire Fund asset	464	464
Other	1,139	1,321
Total current assets	8,955	9,374
Property, Plant, and Equipment
Electric	68,054	66,982
Gas	24,548	24,135
Construction work in progress	2,895	2,757
Other	23	18
Total property, plant, and equipment	95,520	93,892
Accumulated depreciation	(28,259)	(27,756)
Net property, plant, and equipment	67,261	66,136
Other Noncurrent Assets
Regulatory assets	9,159	8,978
Nuclear decommissioning trusts	3,592	3,538
Operating lease right of use asset	1,655	1,736
Wildfire Fund asset	5,700	5,816
Income taxes receivable	67	66
Other	1,898	1,818
Total other noncurrent assets	22,071	21,952
TOTAL ASSETS	98,287	97,462
Current Liabilities
Short-term borrowings	1,448	3,547
Long-term debt, classified as current	1,496	0
Accounts payable:
Trade creditors	2,140	2,366
Regulatory balancing accounts	1,368	1,245
Other	712	624
Operating lease liabilities	531	530
Interest payable	264	444
Disputed claims and customer refunds	244	242
Wildfire-related claims	1,692	2,250
Other	2,259	2,248
Total current liabilities	12,154	13,496
Noncurrent Liabilities
Long-term debt (includes $650 million and $1.0 billion related to VIEs at respective dates)	33,206	32,664
Regulatory liabilities	11,204	10,424
Pension and other post-retirement benefits	2,295	2,328
Asset retirement obligations	6,494	6,412
Deferred income taxes	1,655	1,570
Operating lease liabilities	1,124	1,206
Other	4,502	3,886
Total noncurrent liabilities	60,480	58,490
Shareholders’ Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	28,286	28,286
Reinvested earnings	(4,208)	(4,385)
Accumulated other comprehensive loss	(5)	(5)
Total shareholders’ equity	25,653	25,476
TOTAL LIABILITIES AND EQUITY	$ 98,287	$ 97,462

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Allowance for doubtful accounts	$ 212	$ 146
Customers, VIE	1,610	1,630
Allowance for doubtful accounts, customers, VIE	211	143
Accrued unbilled revenue	897	959
Long-term debt, VIE	$ 650	$ 1,000
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized (in shares)	3,600,000,000	3,600,000,000
Common stock, shares outstanding (in shares)	1,985,105,703	1,984,678,673
Pacific Gas & Electric Co (Utility)
Allowance for doubtful accounts	$ 212	$ 146
Customers, VIE	1,610	1,630
Allowance for doubtful accounts, customers, VIE	211	143
Accrued unbilled revenue	897	959
Long-term debt, VIE	$ 650	$ 1,000
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	264,374,809	264,374,809

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash Flows from Operating Activities
Net income	$ 123	$ 374
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	888	855
Allowance for equity funds used during construction	(32)	(10)
Deferred income taxes and tax credits, net	78	197
Reorganization items, net (Note 2)	(46)	50
Wildfire Fund expense	119	0
Other	117	35
Effect of changes in operating assets and liabilities:
Accounts receivable	111	(22)
Wildfire-related insurance receivable	(28)	0
Inventories	14	3
Accounts payable	143	245
Wildfire-related claims	(558)	0
Income taxes receivable/payable	0	0
Other current assets and liabilities	(175)	(123)
Regulatory assets, liabilities, and balancing accounts, net	340	(310)
Liabilities subject to compromise	0	208
Other noncurrent assets and liabilities	104	103
Net cash provided by operating activities	1,198	1,605
Cash Flows from Investing Activities
Capital expenditures	(1,778)	(1,641)
Proceeds from sales and maturities of nuclear decommissioning trust investments	551	533
Purchases of nuclear decommissioning trust investments	(578)	(552)
Other	9	5
Net cash used in investing activities	(1,796)	(1,655)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	500
Debtor-in-possession credit facility debt issuance costs	0	(3)
Bridge facility financing fees	0	(66)
Borrowings under revolving credit facilities	1,985	0
Repayments under revolving credit facilities	(4,440)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $18	2,382	0
Repayment of long-term debt	(7)	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	350	0
Other	(41)	9
Net cash provided by financing activities	229	440
Net change in cash, cash equivalents, and restricted cash	(369)	390
Cash, cash equivalents, and restricted cash at January 1	627	1,577
Cash, cash equivalents, and restricted cash at March 31	258	1,967
Less: Restricted cash and restricted cash equivalents	(29)	(7)
Cash and cash equivalents	229	1,960
Cash paid for:
Interest, net of amounts capitalized	(550)	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	528	326
Operating lease liabilities arising from obtaining right-of-use assets	4	13
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net income	177	451
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	888	855
Allowance for equity funds used during construction	(32)	(10)
Deferred income taxes and tax credits, net	92	202
Reorganization items, net (Note 2)	(15)	(11)
Wildfire Fund expense	119	0
Other	112	40
Effect of changes in operating assets and liabilities:
Accounts receivable	115	(30)
Wildfire-related insurance receivable	(28)	0
Inventories	14	3
Accounts payable	107	221
Wildfire-related claims	(558)	0
Income taxes receivable/payable	0	0
Other current assets and liabilities	(150)	(121)
Regulatory assets, liabilities, and balancing accounts, net	340	(310)
Liabilities subject to compromise	0	208
Other noncurrent assets and liabilities	102	114
Net cash provided by operating activities	1,283	1,612
Cash Flows from Investing Activities
Capital expenditures	(1,778)	(1,641)
Proceeds from sales and maturities of nuclear decommissioning trust investments	551	533
Purchases of nuclear decommissioning trust investments	(578)	(552)
Other	9	5
Net cash used in investing activities	(1,796)	(1,655)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	0	500
Debtor-in-possession credit facility debt issuance costs	0	(3)
Bridge facility financing fees	0	(30)
Borrowings under revolving credit facilities	1,985	0
Repayments under revolving credit facilities	(4,440)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $18	2,382	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	350	0
Other	(12)	9
Net cash provided by financing activities	265	476
Net change in cash, cash equivalents, and restricted cash	(248)	433
Cash, cash equivalents, and restricted cash at January 1	404	1,129
Cash, cash equivalents, and restricted cash at March 31	156	1,562
Less: Restricted cash and restricted cash equivalents	(29)	(7)
Cash and cash equivalents	127	1,555
Cash paid for:
Interest, net of amounts capitalized	(467)	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	528	326
Operating lease liabilities arising from obtaining right-of-use assets	$ 4	$ 13

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	Mar. 31, 2021USD ($)
Net of discount and issuance costs	$ (18)
Pacific Gas & Electric Co (Utility)
Net of discount and issuance costs	$ (18)

CONDENSED CONSOLIDATED STATEM_6

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Common Stock	Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)	Total Shareholders’ Equity	Non- controlling Interest - Preferred Stock of Subsidiary	Pacific Gas & Electric Co (Utility)	Pacific Gas & Electric Co (Utility)Preferred Stock	Pacific Gas & Electric Co (Utility)Common Stock	Pacific Gas & Electric Co (Utility)Additional Paid-in Capital	Pacific Gas & Electric Co (Utility)Reinvested Earnings	Pacific Gas & Electric Co (Utility)Accumulated Other Comprehensive Income (Loss)	Pacific Gas & Electric Co (Utility)Total Shareholders’ Equity
Beginning balance (in shares) at Dec. 31, 2019		529,236,741
Beginning balance at Dec. 31, 2019	$ 5,388	$ 13,038	$ (7,892)	$ (10)	$ 5,136	$ 252		$ 258	$ 1,322	$ 8,550	$ (4,796)	$ 1	$ 5,335
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	374		374		374		$ 451				451		451
Other comprehensive income (loss)	0			0	0
Common stock issued, net (in shares)		549,155
Common stock issued, net	0	$ 0			0
Stock-based compensation amortization	(3)	$ (3)			(3)
Ending balance (in shares) at Mar. 31, 2020		529,785,896
Ending balance at Mar. 31, 2020	$ 5,759	$ 13,035	(7,518)	(10)	5,507	252		258	1,322	8,550	(4,345)	1	5,786
Beginning balance (in shares) at Dec. 31, 2020	1,984,678,673	1,984,678,673					264,374,809
Beginning balance at Dec. 31, 2020	$ 21,253	$ 30,224	(9,196)	(27)	21,001	252		258	1,322	28,286	(4,385)	(5)	25,476
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	123		123		123		$ 177				177		177
Other comprehensive income (loss)	1			1	1
Common stock issued, net (in shares)		427,030
Common stock issued, net	0	$ 0			0
Stock-based compensation amortization	$ 2	$ 2			2
Ending balance (in shares) at Mar. 31, 2021	1,985,105,703	1,985,105,703					264,374,809
Ending balance at Mar. 31, 2021	$ 21,379	$ 30,226	$ (9,073)	$ (26)	$ 21,127	$ 252		$ 258	$ 1,322	$ 28,286	$ (4,208)	$ (5)	$ 25,653

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2021
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 quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. 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 Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2020 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2020 Form 10-K. This quarterly report should be read in conjunction with the 2020 Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

BANKRUPTCY FILING

BANKRUPTCY FILING	3 Months Ended
	Mar. 31, 2021
Reorganizations [Abstract]
BANKRUPTCY FILING	BANKRUPTCY FILING Chapter 11 Proceedings On the Petition Date, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective Date, PG&E Corporation and the Utility continued to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. On June 20, 2020, the Bankruptcy Court entered the Confirmation Order confirming the Plan filed on June 19, 2020. PG&E Corporation and the Utility emerged from Chapter 11 on the Effective Date of July 1, 2020. Except as otherwise set forth in the Plan, the Confirmation Order or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan. Unresolved Chapter 11 Claims PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts, and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including asserted litigation claims, trade creditor claims, non-qualified benefit plan claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order. Amounts expected to be allowed are reflected as current or noncurrent liabilities in the Condensed Consolidated Balance Sheets. The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order. However, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Effective Date, including but not limited to, claims arising from or relating to indemnification or contribution claims, including with respect to the wildfire that began on November 8, 2018 near the city of Paradise, Butte County, California (the “2018 Camp fire”), the 2017 Northern California wildfires, and the wildfire that began September 9, 2015 in Amador and Calaveras counties in Northern California (the “2015 Butte fire”). In addition, Subordinated Debt Claims and Holdco Rescission or Damage Claims continue to be pursued against PG&E Corporation and the Utility in the claims reconciliation process in the Bankruptcy Court, and claims against certain former directors and current and former officers, as well as certain underwriters, are being pursued in the purported securities class action that is further described in Note 10 under the heading “Securities Class Action Litigation.” Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. At March 31, 2021 and December 31, 2020, respectively, the Condensed Consolidated Balance Sheets reflected $244 million and $242 million in net claims within Disputed claims and customer refunds. Pursuant to the Plan, on and after the Effective Date, the holders of such claims are entitled to pursue their claims against the Reorganized Utility as if the Chapter 11 Cases had not been commenced. On September 1, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court requesting that the court approve an alternative dispute resolution process for resolving disputed general unsecured claims and appoint a panel of mediators in the process. On September 25, 2020, the court approved the motion and appointed a panel of mediators. The mediators’ role will be to assist various claims through a Standard and Abbreviated Mediation Process. On October 27, 2020, PG&E Corporation and the Utility filed a motion for entry of an order extending the deadline for PG&E Corporation and the Utility to object to claims, requesting an additional 180 days beyond December 31, 2020 to process claims. On April 5, 2021, the Bankruptcy Court entered an order further extending the deadline to object to claims through and including December 23, 2021, except for certain claims filed by Cal Fire, for which the deadline is September 30, 2021, in each case without prejudice to the rights of PG&E Corporation and the Utility to seek additional extensions thereof. By stipulation approved by the Bankruptcy Court, the objection deadline for certain claims asserted by the United States is July 30, 2021 or September 30, 2021, depending on the claim. Reorganization Items, Net Reorganization items, net, represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income and other. Cash paid for reorganization items, net was $29 million and $17 million for PG&E Corporation and the Utility, respectively, during the three months ended March 31, 2021 as compared to $57 million and $117 million fo r PG&E Corporation and the Utility, respectively, during the same period in 2020. Reorganization items, net for the three months ended March 31, 2021 and 2020 include the following: Three Months Ended March 31, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 5 (2) 3 Other (3) — (3) Total reorganization items, net $ 2 $ (2) $ — (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Three Months Ended March 31, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 3 $ — $ 3 Legal and other (2) 95 84 179 Interest income (5) (1) (6) Total reorganization items, net $ 93 $ 83 $ 176 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Includes bridge loan facility fees.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESFor a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIE The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Condensed Consolidated Balance Sheets. As of March 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated. The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the period ended March 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of March 31, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.5 billion and $2.6 billion, respectively, and outstanding borrowings of $650 million and $1.0 billion, respectively, under the Receivables Securitization Program. Non-Consolidated VIEs Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at March 31, 2021, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at March 31, 2021, it did not consolidate any of them. Pension and Other Post-Retirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2021 and 2020 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 147 $ 132 $ 16 $ 15 Interest cost 161 178 13 16 Expected return on plan assets (261) (261) (35) (34) Amortization of prior service cost (1) (1) 4 3 Amortization of net actuarial loss 1 1 (8) (5) Net periodic benefit cost 47 49 (10) (5) Regulatory account transfer (2) 37 34 — — Total $ 84 $ 83 $ (10) $ (5) (1) A portion of service costs are capitalized pursuant to GAAP. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) consisted of the following: Pension Other Total (in millions, net of income tax) Three Months Ended March 31, 2021 Beginning balance $ (39) $ 17 $ (22) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $0 and $2, respectively) 1 (6) (5) Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 3 4 Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (38) $ 17 $ (21) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended March 31, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $0, and $2, respectively) 1 (3) (2) Regulatory account transfer (net of taxes of $0 and $1, respectively) — 1 1 Net current period other comprehensive gain (loss) — — — Ending balance $ (22) $ 17 $ (5) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which will be combined in the 2023 GRC. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer: Three Months Ended March 31, (in millions) 2021 2020 Electric Revenue from contracts with customers Residential $ 1,464 $ 1,242 Commercial 1,013 1,007 Industrial 327 341 Agricultural 152 123 Public street and highway lighting 17 17 Other (1) (64) (66) Total revenue from contracts with customers - electric 2,909 2,664 Regulatory balancing accounts (2) 486 376 Total electric operating revenue $ 3,395 $ 3,040 Natural gas Revenue from contracts with customers Residential $ 1,208 $ 1,066 Commercial 245 234 Transportation service only 326 348 Other (1) (47) (22) Total revenue from contracts with customers - gas 1,732 1,626 Regulatory balancing accounts (2) (411) (360) Total natural gas operating revenue 1,321 1,266 Total operating revenues $ 4,716 $ 4,306 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Initial and annual contributions to the Wildfire Fund established pursuant to AB 1054 The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by California’s three large electric IOUs for at least a 10 year period. The contributions from the IOUs will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from customers. The costs of the initial and annual contributions are allocated among the IOUs pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable IOU’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. San Diego Gas & Electric Company and Southern California Edison made their initial contributions to the Wildfire Fund in September 2019. On December 30, 2020, the Utility made its second annual contribution of $193 million to the Wildfire Fund. As of March 31, 2021, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. As of March 31, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other non-current liabilities, $464 million in current assets - Wildfire Fund asset, and $5.7 billion in non-current assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended March 31, 2021, the Utility recorded amortization and accretion expense of $119 million. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income. Expected contributions recorded in Wildfire Fund asset on the Condensed Consolidated Balance Sheets are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset. AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation that began with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment, and subsequently plan to add an additional year of data each following year. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation creates annual distributions of potential losses due to fires that could be attributed to the participating electric utilities. Starting with a 5 year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would have decreased the amortization period to 6 years. Similarly, a ten percent change to the assumption regarding current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness. Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. Financial Instruments—Credit Losses PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to current economic conditions. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. During the three months ended March 31, 2021, expected credit losses of $76 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. Of these amounts recorded during the three months ended March 31, 2021, $49 million and $7 million were deemed probable of recovery and deferred to the CPPMA and a FERC regulatory asset, respectively. Sale of Transmission Tower Wireless Licenses On February 16, 2021, the Utility granted to a subsidiary of SBA Communications Corporation (such subsidiary, “SBA”) an exclusive license enabling SBA to sublicense and market wireless communications equipment attachment locations (“Cell Sites”) on more than 700 of the Utility’s electric transmission towers, telecommunications towers, monopoles, buildings or other structures (collectively, the “Effective Date Towers”) to wireless telecommunication carriers (“Carriers”) for attachment of wireless communications equipment, as contemplated by a Master Transaction Agreement (the “Transaction Agreement”) dated February 2, 2021, between the Utility and SBA. Pursuant to the Transaction Agreement, the Utility also assigned to SBA license agreements between the Utility and Carriers for substantially all of the existing Cell Sites on the Effective Date Towers. The exclusive license was granted pursuant to a Master Multi-Site License Agreement (the “License Agreement”) between the Utility and SBA. The term of the License Agreement is for 100 years. The Utility has the right to terminate the license for individual Cell Sites for certain regulatory or utility operational reasons, with a corresponding payment to SBA. Pursuant to the License Agreement, SBA is entitled to the sublicensing revenue generated by new sublicenses of Cell Sites on the Effective Date Towers, subject to the Utility’s right to a percentage of such sublicensing revenue. The Utility and SBA also entered into a Master Transmission Tower Site License Agreement (the “Tower Site Agreement”), pursuant to which SBA received the exclusive rights to sublicense and market additional attachment locations on up to 28,000 of the Utility’s other electric transmission towers to Carriers for attachment of wireless communications equipment. The Tower Site Agreement provides for a split of license fees from Carriers between the Utility and SBA. The Tower Site Agreement has a licensing period of up to 15 years, depending on SBA’s achievement of certain performance metrics, and any sites licensed during such licensing period will continue to be subject to the Tower Site Agreement for the same term as the License Agreement. In addition, the Utility and SBA entered into a Pipeline Cell Site Transaction Agreement pursuant to which the Utility and SBA established terms and conditions for adding additional cell sites under the License Agreement. Pipeline Cell Sites are locations where the Utility was in the process of locating a new Cell Site for a wireless carrier at the close of the transaction. In exchange for the exclusive license and entry into the License Agreement, SBA agreed to pay the Utility a purchase price of $973 million. SBA paid the Utility $946 million of such purchase price at the closing pursuant to the Transaction Agreement, which also contemplates the post-closing assignment of additional specified Cell Sites to SBA upon the satisfaction of certain terms and conditions, for which SBA will make additional purchase price payments to the Utility. The closing settlement also reflected an adjustment for an estimated amount of payments received by the Utility from Carriers in the pre-closing period that are allocable to licenses in the post-closing period. The purchase price is subject to further adjustment pursuant to the terms of the Transaction Agreement through June 30, 2021. The Utility recorded approximately $365 million of the $946 million sales proceeds as a financing obligation, as this portion of the proceeds for existing Cell Sites represents a sale of future revenues. The Utility recorded approximately $106 million of the $946 million sales proceeds as a contract liability (deferred revenue), as a portion of proceeds with respect to the sublicensing of Cell Sites, as well as the Tower Site Agreement represents an upfront payment for access to space on the Utility’s assets. The Utility utilized a discounted cash flow model based on business assumptions and estimates to determine the allocation of the purchase price between the financing obligation and deferred revenue. The financing obligation and deferred revenue are presented within Other non-current liabilities on the Condensed Consolidated Balance Sheets. The Utility recorded the remaining approximately $475 million ($471 million of which is noncurrent) of the sale proceeds to a regulatory liability, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices. The Utility will amortize the financing obligation through Electric operating revenue and Interest expense on the Condensed Consolidated Statements of Income using the effective interest method and will amortize the deferred revenue balance through Electric operating revenue ratably over the 100-year term. Recently Adopted Accounting Standards Income Taxes In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , which amends the existing guidance to reduce complexity relating to Income Tax disclosures. PG&E Corporation and the Utility adopted this ASU on January 1, 2021. There was no material impact to PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU. Accounting Standards Issued But Not Yet Adopted Debt In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

REGULATORY ASSETS, LIABILITIES,

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	3 Months Ended
	Mar. 31, 2021
Regulated Operations [Abstract]
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Regulatory Assets Long-term regulatory assets are comprised of the following: Balance at (in millions) March 31, 2021 December 31, 2020 Pension benefits (1) $ 2,208 $ 2,245 Environmental compliance costs 1,038 1,112 Utility retained generation (2) 168 181 Price risk management 228 204 Unamortized loss, net of gain, on reacquired debt 46 49 Catastrophic event memorandum account (3) 879 842 Wildfire expense memorandum account (4) 393 400 Fire hazard prevention memorandum account (5) 107 137 Fire risk mitigation memorandum account (6) 58 66 Wildfire mitigation plan memorandum account (7) 359 390 Deferred income taxes (8) 1,075 908 Insurance premium costs (9) 225 294 Wildfire mitigation balancing account (10) 156 156 General rate case memorandum accounts (11) 349 376 Vegetation management balancing account (12) 594 592 COVID-19 pandemic protection memorandum accounts (13) 132 84 Other 1,144 942 Total long-term regulatory assets $ 9,159 $ 8,978 (1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. (2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of March 31, 2021, $54 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval. (4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval. (6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through March 31, 2021. Recovery of WMPMA costs is subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. (10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through March 31, 2021. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 22 months, beginning March 1, 2021. (12) Represents costs from routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval. (13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of March 31, 2021, the Utility had recorded an aggregate under-collection of $122 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $10 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval. Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Balance at (in millions) March 31, 2021 December 31, 2020 Cost of removal obligations (1) $ 7,035 $ 6,905 Recoveries in excess of AROs (2) 452 458 Public purpose programs (3) 983 948 Employee benefit plans (4) 1,002 995 Tower Licenses (5) 471 — Other 1,261 1,118 Total long-term regulatory liabilities $ 11,204 $ 10,424 (1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets. (2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 9 below.) (3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. (4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans. (5) Represents the portion of the net proceeds received from the sale of transmission tower wireless licenses that will be returned to customers. Of the $471 million, $333 million and $138 million will be refunded to FERC and CPUC jurisdiction customers, respectively. (See Note 3 above.) Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) March 31, 2021 December 31, 2020 Electric distribution $ 266 $ — Gas distribution and transmission 3 102 Energy procurement 346 413 Public purpose programs 309 292 Fire hazard prevention memorandum account 121 121 Fire risk mitigation memorandum account 33 33 Wildfire mitigation plan memorandum account 161 161 Wildfire mitigation balancing account 29 27 General rate case memorandum accounts 468 313 Vegetation management balancing account 49 115 Insurance premium costs 157 135 Other 307 289 Total regulatory balancing accounts receivable $ 2,249 $ 2,001 Payable Balance at (in millions) March 31, 2021 December 31, 2020 Electric distribution $ — $ 55 Electric transmission 260 267 Gas distribution and transmission 280 76 Energy procurement 116 158 Public purpose programs 372 410 Other 340 279 Total regulatory balancing accounts payable $ 1,368 $ 1,245 For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K.

DEBT

DEBT	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
DEBT	DEBT Credit Facilities The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at March 31, 2021: (in millions) Termination Facility Limit Borrowings Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility July 2023 $ 3,500 (1) $ — $ 979 $ 2,521 Utility term loan credit facility (2) January 2022 1,500 1,500 — — Utility receivables securitization program (3) October 2022 1,000 (4) 650 — 350 (4) PG&E Corporation revolving credit facility July 2023 500 — — 500 Total credit facilities $ 6,500 $ 2,150 $ 979 $ 3,371 (1) Includes a $1.5 billion letter of credit sublimit. (2) On March 11, 2021, the Utility prepaid in full all amounts outstanding with respect to the $1.5 billion term loan due on June 30, 2021. The remaining $1.5 billion term loan due on January 1, 2022 remains outstanding. (3) On October 5, 2020, the Utility entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. For more information, see “Variable Interest Entities” in Note 3. (4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility 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 from time to time. As of April 22, 2021, the Receivables Securitization Program had a maximum borrowing base of $888 million and was fully drawn. Long-Term Debt Issuances and Redemptions Utility In March 2021, the Utility issued $1.5 billion aggregate principal amount of 1.367% First Mortgage Bonds due March 10, 2023, $450 million aggregate principal amount of 3.25% First Mortgage Bonds due June 1, 2031, and $450 million aggregate principal amount of 4.20% First Mortgage Bonds due June 1, 2041. The proceeds were used for (i) the prepayment of all of the $1.5 billion 364-day term loan facility (maturing June 30, 2021) outstanding under the Utility’s term loan credit agreement, (ii) the repayment of all of the borrowings outstanding under the Utility’s revolving credit facility pursuant to the revolving credit agreement and (iii) general corporate purposes. PG&E Corporation On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”). The Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan in an amount equal to $6.875 million on the last day of each quarter.

EQUITY

EQUITY	3 Months Ended
	Mar. 31, 2021
Equity [Abstract]
EQUITY	EQUITY Ownership Restrictions in PG&E Corporation’s Amended Articles Under section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally five percent shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles of Incorporation (the “Amended Articles”) limit Transfers (as defined in the Amended Articles) that increase a person’s or entity’s (including certain groups of persons) ownership of PG&E Corporation’s equity securities to 4.75% or more prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust. As of the date of this report, it is more likely than not that PG&E Corporation has not undergone an ownership change and consequently, its net operating loss carryforwards and other tax attributes are not limited by section 382 of the Internal Revenue Code. In addition, the tax deduction recorded reflects PG&E Corporation’s conclusion as of March 31, 2021 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time transfers of cash and other property (including PG&E Corporation common stock) were made to the Fire Victim Trust. In January 2021, PG&E Corporation received an IRS ruling that states the Utility is eligible to make a grantor trust election for U.S. federal income tax purposes with respect to the Fire Victim Trust and addressed certain, but not all, related issues. PG&E Corporation believes benefits associated with “grantor trust” treatment, including, a potentially larger tax deduction related to the proceeds realized by the Fire Victim Trust from the sale of shares contributed to the Fire Victim Trust, could be realized, but only if PG&E Corporation and the Fire Victim Trust can meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. PG&E Corporation expects to elect grantor trust treatment if it is able to enter into a definitive agreement regarding the same with the Fire Victim Trust. On April 28, 2021, the Bankruptcy Court issued an oral ruling that it would approve the material terms of an agreement between PG&E Corporation, the Utility and the Fire Victim Trust that supports the election of the grantor trust treatment. There can be no assurance that the parties will execute a definitive agreement or that PG&E Corporation will be able to avail itself of the benefits of a grantor trust election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur only at the time the Fire Victim Trust pays the fire victims and will be impacted by the price at which the Fire Victim Trust sells the shares, rather than the price at the time such shares were contributed to the Fire Victim Trust. Dividends On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018. Subject to the dividend restrictions as described in Note 6 of the Notes to the Consolidated Financial Statements in Item 8 of the 2020 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of March 31, 2021, it is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

EARNINGS PER SHARE

EARNINGS PER SHARE	3 Months Ended
	Mar. 31, 2021
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 available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended March 31, (in millions, except per share amounts) 2021 2020 Income attributable to common shareholders $ 120 $ 371 Weighted average common shares outstanding, basic 1,985 529 Add incremental shares from assumed conversions: Employee share-based compensation 5 — Equity Units 141 119 Weighted average common shares outstanding, diluted 2,131 648 Total Income per common share, diluted $ 0.06 $ 0.57

DERIVATIVES

DERIVATIVES	3 Months Ended
	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments March 31, 2021 December 31, 2020 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 219,348,075 146,642,863 Options 17,080,000 14,140,000 Electricity (MWh) Forwards, Futures and Swaps 11,127,600 9,435,830 Options 588,800 — Congestion Revenue Rights (3) 264,206,953 266,091,470 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At March 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 50 $ (3) $ 105 $ 152 Noncurrent assets – other 136 — — 136 Current liabilities – other (41) 3 17 (21) Noncurrent liabilities – other (228) — 3 (225) Total commodity risk $ (83) $ — $ 125 $ 42 At December 31, 2020, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 33 $ — $ 115 $ 148 Noncurrent assets – other 136 — — 136 Current liabilities – other (38) — 15 (23) Noncurrent liabilities – other (204) — 10 (194) Total commodity risk $ (73) $ — $ 140 $ 67 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. Some of the Utility’s derivatives instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. Multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of March 31, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Other inputs that are directly or indirectly observable in the marketplace. • Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements March 31, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 228 $ — $ — $ — $ 228 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 2,461 — — — 2,461 Fixed-income securities 953 812 — — 1,765 Assets measured at NAV — — — — 27 Total nuclear decommissioning trusts (2) 3,443 812 — — 4,282 Price risk management instruments (Note 8) Electricity — 17 165 1 183 Gas — 4 — 101 105 Total price risk management instruments — 21 165 102 288 Rabbi trusts Fixed-income securities — 102 — — 102 Life insurance contracts — 76 — — 76 Total rabbi trusts — 178 — — 178 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 158 Total long-term disability trust 5 — — — 163 TOTAL ASSETS $ 3,676 $ 1011 $ 165 $ 102 $ 5,139 Liabilities: Price risk management instruments (Note 8) Electricity — 5 259 (20) 244 Gas — 5 — (3) 2 TOTAL LIABILITIES $ — $ 10 $ 259 $ (23) $ 246 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $690 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2020 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 470 $ — $ — $ — $ 470 Nuclear decommissioning trusts Short-term investments 27 — — — 27 Global equity securities 2,398 — — — 2,398 Fixed-income securities 924 835 — — 1,759 Assets measured at NAV — — — — 25 Total nuclear decommissioning trusts (2) 3,349 835 — — 4,209 Price risk management instruments (Note 8) Electricity — 2 166 2 170 Gas — 1 — 113 114 Total price risk management instruments — 3 166 115 284 Rabbi trusts Fixed-income securities — 106 — — 106 Life insurance contracts — 79 — — 79 Total rabbi trusts — 185 — — 185 Long-term disability trust Short-term investments 9 — — — 9 Assets measured at NAV — — — — 158 Total long-term disability trust 9 — — — 167 TOTAL ASSETS $ 3,828 $ 1,023 $ 166 $ 115 $ 5,315 Liabilities: Price risk management instruments (Note 8) Electricity — 1 238 (25) 214 Gas — 3 — — 3 TOTAL LIABILITIES $ — $ 4 $ 238 $ (25) $ 217 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the three months ended March 31, 2021 and 2020. Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued as Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Uncertainty Analysis Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 8 above.) Fair Value at (in millions) March 31, 2021 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) / Weighted-Average Price (2) Congestion revenue rights $ 148 $ 79 Market approach CRR auction prices $(320.25) - $320.25 / 0.27 Power purchase agreements $ 17 $ 180 Discounted cash flow Forward prices $13.43 - $233.55 / 39.56 (1) Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) December 31, 2020 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 153 $ 74 Market approach CRR auction prices $(320.25) - $320.25 / 0.3 Power purchase agreements $ 13 $ 164 Discounted cash flow Forward prices $12.56 - $148.30 / 35.52 (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 instruments for the three months ended March 31, 2021 and 2020: Price Risk Management Instruments (in millions) 2021 2020 Asset balance as of January 1 $ (72) $ 5 Net realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts (1) (22) (10) Asset (liability) balance as of March 31 $ (94) $ (5) (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Financial Instruments PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable; short-term borrowings; accounts payable; and customer deposits approximate their carrying values at March 31, 2021 and December 31, 2020, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At March 31, 2021 At December 31, 2020 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation $ 3,372 $ 2,118 $ 1,901 $ 2,175 Utility 32,056 33,200 29,664 32,632 Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Unrealized Gains Total Unrealized Losses Total Fair As of March 31, 2021 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 527 1,963 (2) 2,488 Fixed-income securities 1,689 94 (18) 1,765 Total (1) $ 2,245 $ 2,057 $ (20) $ 4,282 As of December 31, 2020 Nuclear decommissioning trusts Short-term investments $ 27 $ — $ — $ 27 Global equity securities 543 1,881 (1) 2,423 Fixed-income securities 1,610 152 (3) 1,759 Total (1) $ 2,180 $ 2,033 $ (4) $ 4,209 (1) Represents amounts before deducting $690 million and $671 million for the periods ended March 31, 2021 and December 31, 2020, respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) March 31, 2021 Less than 1 year $ 32 1–5 years 501 5–10 years 427 More than 10 years 805 Total maturities of fixed-income securities $ 1,765 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended March 31, (in millions) 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 551 $ 533 Gross realized gains on securities 55 18 Gross realized losses on securities (13) (9)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
WILDFIRE-RELATED CONTINGENCIES	WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement (as defined below), and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation, the Utility, the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments. On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility paid the first tranche of tax benefits of approximately $758 million pursuant to the Tax Benefits Payment Agreement, leaving approximately $592 million to be paid. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”), indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons. On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized. The Utility submitted electric incident reports to the CPUC indicating that: • at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose; • various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time; • at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006; • at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and • on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower. On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint (the “Complaint”) charging the Utility with 5 felonies and 28 misdemeanors related to the 2019 Kincade fire. The Complaint alleges three felony counts of recklessly causing a fire that caused great bodily injury to six firefighters and/or burned inhabited and other structures, inhabited property, forest land and personal property, in violation of Penal Code section 452; two felony counts of reckless emission of air contaminants that caused great bodily injury to two minors, in violation of Health and Safety Code section 42400.3(c); one misdemeanor count of carelessly or negligently throwing or placing substances that may cause a fire, in violation of Health and Safety Code section 13001; one misdemeanor count of negligently causing fire, in violation of Public Resources Code section 4421; three misdemeanor counts of violation by a public utility, in violation of Public Utilities Code section 2110; and 23 misdemeanor counts of recklessly or negligently emitting air contaminants, in violation of Health and Safety Code sections 42400.3(b) and 42400.1(a). If convicted of any of the charges in the Complaint, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorney's fees and interest), as well as non-monetary remedies such as oversight requirements. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Complaint. It further announced that it will accept Cal Fire’s finding that a PG&E transmission line caused the 2019 Kincade fire, even though PG&E Corporation does not have access to the evidence that Cal Fire gathered. On April 20, 2021, the court held an initial hearing in the case. Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.) In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, other information gathered as part of PG&E Corporation’s and the Utility’s investigation, and the charges filed by the Sonoma County District Attorney’s Office, 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 charge in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with certain subrogation entities and certain county and local agencies, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2019 Kincade fire of $175 million for the three months ended March 31, 2021, for an aggregate liability of $800 million (before available insurance). The aggregate liability of $800 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $800 million estimate does not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Complaint, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victim and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Complaint, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire would materially exceed the $800 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2019 Kincade fire civil claims. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $800 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceedings initiated against the Utility by the Sonoma County District Attorney’s Office. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire or the Sonoma County 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 potential damages. The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date, and various other entities may also be investigating the fire. It is uncertain when any such investigations will be complete. As of April 28, 2021, PG&E Corporation and the Utility are aware of 25 complaints on behalf of approximately 535 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. On April 8, 2021, the coordination motion judge ordered that the cases be coordinated, and on April 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2019 Kincade fire, including if PG&E Corporation or the Utility were found to have been negligent. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management. On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that: • wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time; • according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area; and • the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes. On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo. Cal Fire also indicated that its investigative report has been forwarded to the Shasta County District Attorney’s Office, which is investigating the matter. PG&E Corporation and the Utility have received and are responding to data requests from the SED and document requests from the Shasta County District Attorney’s Office relating to the 2020 Zogg fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a charge in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with certain agencies and additional damages information from certain plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire in the amount of $25 million for the three months ended March 31, 2021, for an aggregate liability of $300 million (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above. The aggregate liability of $300 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $300 million estimate does not include, among other things: (i) any amounts for potential penalties, fines or restitution that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $300 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties. The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for $247 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $300 million probable loss estimate less an initial self-insured retention of $60 million, plus $7 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. As of April 28, 2021, PG&E Corporation and the Utility are aware of 7 complaints on behalf of approximately 266 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court. On March 15, 2021, PG&E Corporation and the Utility filed a brief that supported coordination but requested that the cases be coordinated in Shasta County Superior Court or, in the alternative, Sacramento County Superior Court. On March 24, 2021, pursuant to authorization from the California Judicial Council, a judge of the San Francisco County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for May 12, 2021. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2020 Zogg fire, including if PG&E Corporation and the Utility were found to have been negligent. Loss Recoveries PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Insurance Coverage In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period of April 12, 2021 to April 1, 2022, and approximately $32 million in wildfire liability reinsurance for the period of April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire reinsurance for the period of July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period of August 1, 2020 to August 1, 2021. On August 1, 2021, this existing wildfire liability coverage is scheduled to renew for the period of August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. For non-wildfire events, the Utility carries approximately $700 million in coverage for the period of August 1, 2020 to August 1, 2021 at a cost of approximately $152 million. At March 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $313 million, reflected in Other current assets on the Condensed Consolidated Balance Sheets. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter is required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate

OTHER CONTINGENCIES AND COMMITM

OTHER CONTINGENCIES AND COMMITMENTS	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
OTHER CONTINGENCIES AND COMMITMENTS	WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Restructuring Support Agreement with the TCC On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA (as incorporated into the Plan) provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that has funded and will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims consists of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $758 million that was paid in cash on January 15, 2021 and (ii) the remaining balance of $592 million to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of the Tax Benefits Payment Agreement (as defined below), and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Pursuant to a stipulation approved by the Bankruptcy Court on June 12, 2020, PG&E Corporation, the Utility, the TCC, and the trustee of the Fire Victim Trust agreed that the percentage ownership of the Fire Victim Trust would be 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments. On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022. On January 15, 2021, the Utility paid the first tranche of tax benefits of approximately $758 million pursuant to the Tax Benefits Payment Agreement, leaving approximately $592 million to be paid. 2019 Kincade Fire According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”), indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons. On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized. The Utility submitted electric incident reports to the CPUC indicating that: • at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose; • various generating facilities on the Geysers #9 Lakeville 230 kV line detected the disturbance and separated at approximately the same time; • at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006; • at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and • on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower. On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. The press release stated that Cal Fire had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” On April 6, 2021, the Sonoma County District Attorney’s office filed a criminal complaint (the “Complaint”) charging the Utility with 5 felonies and 28 misdemeanors related to the 2019 Kincade fire. The Complaint alleges three felony counts of recklessly causing a fire that caused great bodily injury to six firefighters and/or burned inhabited and other structures, inhabited property, forest land and personal property, in violation of Penal Code section 452; two felony counts of reckless emission of air contaminants that caused great bodily injury to two minors, in violation of Health and Safety Code section 42400.3(c); one misdemeanor count of carelessly or negligently throwing or placing substances that may cause a fire, in violation of Health and Safety Code section 13001; one misdemeanor count of negligently causing fire, in violation of Public Resources Code section 4421; three misdemeanor counts of violation by a public utility, in violation of Public Utilities Code section 2110; and 23 misdemeanor counts of recklessly or negligently emitting air contaminants, in violation of Health and Safety Code sections 42400.3(b) and 42400.1(a). If convicted of any of the charges in the Complaint, the Utility could be subject to fines, penalties, and restitution to victims for their economic losses (including property damage, medical and mental health expenses, lost wages, lost profits, attorney's fees and interest), as well as non-monetary remedies such as oversight requirements. On April 6, 2021, PG&E Corporation announced that it disputed the charges in the Complaint. It further announced that it will accept Cal Fire’s finding that a PG&E transmission line caused the 2019 Kincade fire, even though PG&E Corporation does not have access to the evidence that Cal Fire gathered. On April 20, 2021, the court held an initial hearing in the case. Potential liabilities related to the 2019 Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by courts or other governmental entities. If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the 2019 Kincade fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires.) In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, other information gathered as part of PG&E Corporation’s and the Utility’s investigation, and the charges filed by the Sonoma County District Attorney’s Office, 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 charge in the aggregate amount of $625 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with certain subrogation entities and certain county and local agencies, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2019 Kincade fire of $175 million for the three months ended March 31, 2021, for an aggregate liability of $800 million (before available insurance). The aggregate liability of $800 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $800 million estimate does not include, among other things: (i) any amounts for potential penalties, fines, or restitution that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable. Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges in the Complaint, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees. This requirement for full reimbursement of economic loss is not waivable by either the government or the victim and is not offset by any compensation that the victims have received or may receive from their insurance carriers. In the event that the Utility were convicted of certain charges in the Complaint, the Utility currently believes that, depending on which charges it were to be convicted of, its total losses associated with the 2019 Kincade fire would materially exceed the $800 million aggregate liability that PG&E Corporation and the Utility have recorded to reflect the lower end of the range of the reasonably estimable range of losses for the 2019 Kincade fire civil claims. The Utility is currently unable to determine a reasonable estimate of the amount of such additional losses. The Utility does not expect that any of its liability insurance would be available to cover restitution payments ordered by the court presiding over the criminal proceeding. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in changes to the accrual depending on the information provided. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $800 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility and the outcome of the criminal proceedings initiated against the Utility by the Sonoma County District Attorney’s Office. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire or the Sonoma County 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 potential damages. The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2019 Kincade fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2019 Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for the full amount of the $430 million. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. PG&E Corporation and the Utility have received data requests from the SED relating to the 2019 Kincade fire and have responded to all data requests received to date, and various other entities may also be investigating the fire. It is uncertain when any such investigations will be complete. As of April 28, 2021, PG&E Corporation and the Utility are aware of 25 complaints on behalf of approximately 535 plaintiffs related to the 2019 Kincade fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. On December 3, 2020, PG&E Corporation and the Utility filed a petition with the California Judicial Council to coordinate the litigation. On April 8, 2021, the coordination motion judge ordered that the cases be coordinated, and on April 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2019 Kincade fire, including if PG&E Corporation or the Utility were found to have been negligent. 2020 Zogg Fire According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed. Of the 204 structures destroyed, 63 were single family homes, according to a damage inspection report available from the Shasta County Department of Resource Management. On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that: • wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time; • according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity starting at approximately 2:40 p.m. until 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area; and • the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes. On March 22, 2021, Cal Fire issued a press release with its determination that the 2020 Zogg fire was caused by a pine tree contacting electrical facilities owned and operated by the Utility located north of the community of Igo. Cal Fire also indicated that its investigative report has been forwarded to the Shasta County District Attorney’s Office, which is investigating the matter. PG&E Corporation and the Utility have received and are responding to data requests from the SED and document requests from the Shasta County District Attorney’s Office relating to the 2020 Zogg fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to the evidence in the possession of Cal Fire or other third parties. Potential liabilities related to the 2020 Zogg fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities. Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2020 Zogg fire. PG&E Corporation and the Utility recorded a charge in the aggregate amount of $275 million for the year ended December 31, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with certain agencies and additional damages information from certain plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire in the amount of $25 million for the three months ended March 31, 2021, for an aggregate liability of $300 million (before available insurance). If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the Zogg fire, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. For more information regarding the inverse condemnation doctrine, see “2019 Kincade Fire” above. The aggregate liability of $300 million for claims in connection with the 2020 Zogg fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses, and is subject to change based on additional information. This $300 million estimate does not include, among other things: (i) any amounts for potential penalties, fines or restitution that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, or (iv) any other amounts that are not reasonably estimable. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss will be greater than $300 million and are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. If the liability for the 2020 Zogg fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. In particular, PG&E Corporation and the Utility have not had access to all of the evidence obtained by Cal Fire or other third parties. The process for estimating losses associated with potential claims related to the 2020 Zogg fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the 2020 Zogg fire may change. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the 2020 Zogg fire in an aggregate amount of $611 million. This amount is reduced from the $867.5 million of coverage disclosed in the 2020 Form 10-K due to the Utility’s commuting certain insurance policies in connection with its April 2021 wildfire liability insurance renewal. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of March 31, 2021, the Utility has recorded an insurance receivable for $247 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $300 million probable loss estimate less an initial self-insured retention of $60 million, plus $7 million in legal fees incurred. PG&E Corporation and the Utility intend to seek full recovery for all insured losses. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. As of April 28, 2021, PG&E Corporation and the Utility are aware of 7 complaints on behalf of approximately 266 plaintiffs related to the 2020 Zogg fire and expect that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Shasta and the California Superior Court for the County of San Francisco and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their distribution lines was the cause of the 2020 Zogg fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages. On February 5, 2021, certain plaintiffs filed a petition with the California Judicial Council to coordinate five civil cases filed against the Utility and PG&E Corporation in the Superior Courts of Shasta and San Francisco counties. The petition requests that the cases be coordinated in San Francisco Superior Court. On March 15, 2021, PG&E Corporation and the Utility filed a brief that supported coordination but requested that the cases be coordinated in Shasta County Superior Court or, in the alternative, Sacramento County Superior Court. On March 24, 2021, pursuant to authorization from the California Judicial Council, a judge of the San Francisco County Superior Court was assigned to serve as the coordination motion judge to decide whether the aforementioned actions should be coordinated and, if so, recommend where the coordinated proceeding should take place. A hearing is scheduled for May 12, 2021. In addition to claims for property damage, business interruption, interest and attorneys’ fees, PG&E Corporation and the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, wrongful death and personal injury damages, punitive damages and other damages under other theories of liability in connection with the 2020 Zogg fire, including if PG&E Corporation and the Utility were found to have been negligent. Loss Recoveries PG&E Corporation and the Utility have insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Insurance Coverage In April 2021, the Utility purchased approximately $268 million in wildfire liability insurance coverage for the period of April 12, 2021 to April 1, 2022, and approximately $32 million in wildfire liability reinsurance for the period of April 1, 2021 to April 1, 2022 at a cost of approximately $220 million. This coverage is in addition to approximately $11 million in existing wildfire reinsurance for the period of July 1, 2020 to July 1, 2021 and approximately $600 million in existing wildfire liability insurance purchased by the Utility in August 2020 for the period of August 1, 2020 to August 1, 2021. On August 1, 2021, this existing wildfire liability coverage is scheduled to renew for the period of August 1, 2021 to August 1, 2022 at a cost of approximately $516 million pursuant to multi-year policy terms. The Utility’s wildfire liability insurance is subject to an initial self-insured retention of $60 million. For non-wildfire events, the Utility carries approximately $700 million in coverage for the period of August 1, 2020 to August 1, 2021 at a cost of approximately $152 million. At March 31, 2021, PG&E Corporation and the Utility had prepaid insurance of $313 million, reflected in Other current assets on the Condensed Consolidated Balance Sheets. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. In the Utility’s 2020 GRC proceeding, the CPUC also approved a settlement agreement provision that allows the Utility to recover annual insurance costs for up to $1.4 billion in general liability insurance coverage. An advice letter is required for additional coverage purchased by the Utility in excess of $1.4 billion in coverage. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any year that do not exceed the greater of $1.0 billion in the aggregate

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation	This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated in consolidation.  The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  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 Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 2020 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2020 Form 10-K.  This quarterly report should be read in conjunction with the 2020 Form 10-K.
Use of Estimates and Assumptions	The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred
Variable Interest Entities	A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Consolidated VIE The SPV created in connection with the Receivables Securitization Program (as defined below in Note 5) in October 2020 is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). Amounts received from the Lenders, the pledged receivables and the corresponding debt are included in Accounts receivable and Long-term debt, respectively, on the Condensed Consolidated Balance Sheets. As of March 31, 2021, the aggregate principal amount of the loans made by the Lenders cannot exceed $1.0 billion outstanding at any time. The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated. The SPV is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the period ended March 31, 2021 or is expected to be provided in the future that was not previously contractually required. As of March 31, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.5 billion and $2.6 billion, respectively, and outstanding borrowings of $650 million and $1.0 billion, respectively, under the Receivables Securitization Program. Non-Consolidated VIEs Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at March 31, 2021, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at March 31, 2021, it did not consolidate any of them.
Pension and Other Post-Retirement Benefits	PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.
Revenue Recognition	Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and GT&S rate cases, which will be combined in the 2023 GRC. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
Financial Instruments—Credit Losses	PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. PG&E Corporation and the Utility have incorporated forward-looking data in their estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to current economic conditions. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted	Recently Adopted Accounting Standards Income Taxes In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes , which amends the existing guidance to reduce complexity relating to Income Tax disclosures. PG&E Corporation and the Utility adopted this ASU on January 1, 2021. There was no material impact to PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements and the related disclosures resulting from the adoption of this ASU. Accounting Standards Issued But Not Yet Adopted Debt In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.
Earnings Per Share	PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders 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 customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.
Fair Value Measurements	PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Other inputs that are directly or indirectly observable in the marketplace. • Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Valuation Techniques	Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. There were no material transfers between any levels for the three months ended March 31, 2021 and 2020. Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued as Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.
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 assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation’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.

BANKRUPTCY FILING (Tables)

BANKRUPTCY FILING (Tables)	3 Months Ended
	Mar. 31, 2021
Reorganizations [Abstract]
Schedule of Debtor Reorganization Items	Reorganization items, net for the three months ended March 31, 2021 and 2020 include the following: Three Months Ended March 31, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 5 (2) 3 Other (3) — (3) Total reorganization items, net $ 2 $ (2) $ — (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Three Months Ended March 31, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 3 $ — $ 3 Legal and other (2) 95 84 179 Interest income (5) (1) (6) Total reorganization items, net $ 93 $ 83 $ 176 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Includes bridge loan facility fees.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Components of Net Periodic Benefit Cost	The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2021 and 2020 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 147 $ 132 $ 16 $ 15 Interest cost 161 178 13 16 Expected return on plan assets (261) (261) (35) (34) Amortization of prior service cost (1) (1) 4 3 Amortization of net actuarial loss 1 1 (8) (5) Net periodic benefit cost 47 49 (10) (5) Regulatory account transfer (2) 37 34 — — Total $ 84 $ 83 $ (10) $ (5) (1) A portion of service costs are capitalized pursuant to GAAP. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)	The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) consisted of the following: Pension Other Total (in millions, net of income tax) Three Months Ended March 31, 2021 Beginning balance $ (39) $ 17 $ (22) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $0 and $2, respectively) 1 (6) (5) Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 3 4 Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (38) $ 17 $ (21) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended March 31, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $0, and $2, respectively) 1 (3) (2) Regulatory account transfer (net of taxes of $0 and $1, respectively) — 1 1 Net current period other comprehensive gain (loss) — — — Ending balance $ (22) $ 17 $ (5) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
Summary of Revenues Disaggregated by Type of Customer	The following table presents the Utility’s revenues disaggregated by type of customer: Three Months Ended March 31, (in millions) 2021 2020 Electric Revenue from contracts with customers Residential $ 1,464 $ 1,242 Commercial 1,013 1,007 Industrial 327 341 Agricultural 152 123 Public street and highway lighting 17 17 Other (1) (64) (66) Total revenue from contracts with customers - electric 2,909 2,664 Regulatory balancing accounts (2) 486 376 Total electric operating revenue $ 3,395 $ 3,040 Natural gas Revenue from contracts with customers Residential $ 1,208 $ 1,066 Commercial 245 234 Transportation service only 326 348 Other (1) (47) (22) Total revenue from contracts with customers - gas 1,732 1,626 Regulatory balancing accounts (2) (411) (360) Total natural gas operating revenue 1,321 1,266 Total operating revenues $ 4,716 $ 4,306 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers.

REGULATORY ASSETS, LIABILITIE_2

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)	3 Months Ended
	Mar. 31, 2021
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Balance at (in millions) March 31, 2021 December 31, 2020 Pension benefits (1) $ 2,208 $ 2,245 Environmental compliance costs 1,038 1,112 Utility retained generation (2) 168 181 Price risk management 228 204 Unamortized loss, net of gain, on reacquired debt 46 49 Catastrophic event memorandum account (3) 879 842 Wildfire expense memorandum account (4) 393 400 Fire hazard prevention memorandum account (5) 107 137 Fire risk mitigation memorandum account (6) 58 66 Wildfire mitigation plan memorandum account (7) 359 390 Deferred income taxes (8) 1,075 908 Insurance premium costs (9) 225 294 Wildfire mitigation balancing account (10) 156 156 General rate case memorandum accounts (11) 349 376 Vegetation management balancing account (12) 594 592 COVID-19 pandemic protection memorandum accounts (13) 132 84 Other 1,144 942 Total long-term regulatory assets $ 9,159 $ 8,978 (1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. (2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. (3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of March 31, 2021, $54 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs is subject to CPUC review and approval. (4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs is subject to CPUC review and approval. (5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs is subject to CPUC review and approval. (6) Includes costs associated with the 2019 WMP for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 and the 2020 WMP for the period of January 1, 2020 through December 31, 2020 and the 2021 WMP for the period of January 1, 2021 through March 31, 2021. Recovery of WMPMA costs is subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) Represents non-current excess liability insurance premium costs recorded to RTBA and Adjustment Mechanism for Costs Determined in Other Proceedings, as authorized in the 2020 GRC and 2019 GT&S rate cases, respectively. (10) Includes costs associated with certain wildfire mitigation activities for the period January 1, 2020 through March 31, 2021. Long-term balance represents costs above 115% of adopted revenue requirements, which are subject to CPUC review and approval. (11) The General Rate Case Memorandum Accounts record the difference between the gas and electric revenue requirements in effect on January 1, 2020 and through February 28, 2021 as authorized by the CPUC in December 2020. These amounts will be recovered in rates over 22 months, beginning March 1, 2021. (12) Represents costs from routine vegetation management and enhanced vegetation management activities previously recorded in the FRMMA/WMPMA, and tree mortality and fire risk reduction work previously recorded in CEMA. Recovery of VMBA costs above 120% of adopted revenue requirements is subject to CPUC review and approval. (13) On April 16, 2020, the CPUC passed a resolution that established the CPPMA to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of March 31, 2021, the Utility had recorded an aggregate under-collection of $122 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $10 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs is subject to CPUC review and approval.
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Balance at (in millions) March 31, 2021 December 31, 2020 Cost of removal obligations (1) $ 7,035 $ 6,905 Recoveries in excess of AROs (2) 452 458 Public purpose programs (3) 983 948 Employee benefit plans (4) 1,002 995 Tower Licenses (5) 471 — Other 1,261 1,118 Total long-term regulatory liabilities $ 11,204 $ 10,424 (1) Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets. (2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments. (See Note 9 below.) (3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs. (4) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long-Term Disability Plans.
Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) March 31, 2021 December 31, 2020 Electric distribution $ 266 $ — Gas distribution and transmission 3 102 Energy procurement 346 413 Public purpose programs 309 292 Fire hazard prevention memorandum account 121 121 Fire risk mitigation memorandum account 33 33 Wildfire mitigation plan memorandum account 161 161 Wildfire mitigation balancing account 29 27 General rate case memorandum accounts 468 313 Vegetation management balancing account 49 115 Insurance premium costs 157 135 Other 307 289 Total regulatory balancing accounts receivable $ 2,249 $ 2,001
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) March 31, 2021 December 31, 2020 Electric distribution $ — $ 55 Electric transmission 260 267 Gas distribution and transmission 280 76 Energy procurement 116 158 Public purpose programs 372 410 Other 340 279 Total regulatory balancing accounts payable $ 1,368 $ 1,245

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities	The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at March 31, 2021: (in millions) Termination Facility Limit Borrowings Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility July 2023 $ 3,500 (1) $ — $ 979 $ 2,521 Utility term loan credit facility (2) January 2022 1,500 1,500 — — Utility receivables securitization program (3) October 2022 1,000 (4) 650 — 350 (4) PG&E Corporation revolving credit facility July 2023 500 — — 500 Total credit facilities $ 6,500 $ 2,150 $ 979 $ 3,371 (1) Includes a $1.5 billion letter of credit sublimit. (2) On March 11, 2021, the Utility prepaid in full all amounts outstanding with respect to the $1.5 billion term loan due on June 30, 2021. The remaining $1.5 billion term loan due on January 1, 2022 remains outstanding. (3) On October 5, 2020, the Utility entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to the SPV, a limited liability company wholly owned by the Utility. For more information, see “Variable Interest Entities” in Note 3. (4) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. The facility 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 from time to time. As of April 22, 2021, the Receivables Securitization Program had a maximum borrowing base of $888 million and was fully drawn.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	3 Months Ended
	Mar. 31, 2021
Earnings Per Share [Abstract]
Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Common Shares Outstanding for Calculating Diluted EPS	The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended March 31, (in millions, except per share amounts) 2021 2020 Income attributable to common shareholders $ 120 $ 371 Weighted average common shares outstanding, basic 1,985 529 Add incremental shares from assumed conversions: Employee share-based compensation 5 — Equity Units 141 119 Weighted average common shares outstanding, diluted 2,131 648 Total Income per common share, diluted $ 0.06 $ 0.57

DERIVATIVES (Tables)

DERIVATIVES (Tables)	3 Months Ended
	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Volumes of Outstanding Derivative Contracts	The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments March 31, 2021 December 31, 2020 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 219,348,075 146,642,863 Options 17,080,000 14,140,000 Electricity (MWh) Forwards, Futures and Swaps 11,127,600 9,435,830 Options 588,800 — Congestion Revenue Rights (3) 264,206,953 266,091,470 (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.
Schedule of Offsetting Assets	At March 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 50 $ (3) $ 105 $ 152 Noncurrent assets – other 136 — — 136 Current liabilities – other (41) 3 17 (21) Noncurrent liabilities – other (228) — 3 (225) Total commodity risk $ (83) $ — $ 125 $ 42 At December 31, 2020, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 33 $ — $ 115 $ 148 Noncurrent assets – other 136 — — 136 Current liabilities – other (38) — 15 (23) Noncurrent liabilities – other (204) — 10 (194) Total commodity risk $ (73) $ — $ 140 $ 67
Schedule of Offsetting Liabilities	At March 31, 2021, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 50 $ (3) $ 105 $ 152 Noncurrent assets – other 136 — — 136 Current liabilities – other (41) 3 17 (21) Noncurrent liabilities – other (228) — 3 (225) Total commodity risk $ (83) $ — $ 125 $ 42 At December 31, 2020, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 33 $ — $ 115 $ 148 Noncurrent assets – other 136 — — 136 Current liabilities – other (38) — 15 (23) Noncurrent liabilities – other (204) — 10 (194) Total commodity risk $ (73) $ — $ 140 $ 67

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 228 $ — $ — $ — $ 228 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 2,461 — — — 2,461 Fixed-income securities 953 812 — — 1,765 Assets measured at NAV — — — — 27 Total nuclear decommissioning trusts (2) 3,443 812 — — 4,282 Price risk management instruments (Note 8) Electricity — 17 165 1 183 Gas — 4 — 101 105 Total price risk management instruments — 21 165 102 288 Rabbi trusts Fixed-income securities — 102 — — 102 Life insurance contracts — 76 — — 76 Total rabbi trusts — 178 — — 178 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 158 Total long-term disability trust 5 — — — 163 TOTAL ASSETS $ 3,676 $ 1011 $ 165 $ 102 $ 5,139 Liabilities: Price risk management instruments (Note 8) Electricity — 5 259 (20) 244 Gas — 5 — (3) 2 TOTAL LIABILITIES $ — $ 10 $ 259 $ (23) $ 246 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $690 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2020 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 470 $ — $ — $ — $ 470 Nuclear decommissioning trusts Short-term investments 27 — — — 27 Global equity securities 2,398 — — — 2,398 Fixed-income securities 924 835 — — 1,759 Assets measured at NAV — — — — 25 Total nuclear decommissioning trusts (2) 3,349 835 — — 4,209 Price risk management instruments (Note 8) Electricity — 2 166 2 170 Gas — 1 — 113 114 Total price risk management instruments — 3 166 115 284 Rabbi trusts Fixed-income securities — 106 — — 106 Life insurance contracts — 79 — — 79 Total rabbi trusts — 185 — — 185 Long-term disability trust Short-term investments 9 — — — 9 Assets measured at NAV — — — — 158 Total long-term disability trust 9 — — — 167 TOTAL ASSETS $ 3,828 $ 1,023 $ 166 $ 115 $ 5,315 Liabilities: Price risk management instruments (Note 8) Electricity — 1 238 (25) 214 Gas — 3 — — 3 TOTAL LIABILITIES $ — $ 4 $ 238 $ (25) $ 217 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $671 million, primarily related to deferred taxes on appreciation of investment value.
Level 3 Measurements and Sensitivity Analysis	Fair Value at (in millions) March 31, 2021 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) / Weighted-Average Price (2) Congestion revenue rights $ 148 $ 79 Market approach CRR auction prices $(320.25) - $320.25 / 0.27 Power purchase agreements $ 17 $ 180 Discounted cash flow Forward prices $13.43 - $233.55 / 39.56 (1) Represents price per MWh. (2) Unobservable inputs were weighted by the relative fair value of the instruments. Fair Value at (in millions) December 31, 2020 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input Range (1) /Weighted-Average Price (2) Congestion revenue rights $ 153 $ 74 Market approach CRR auction prices $(320.25) - $320.25 / 0.3 Power purchase agreements $ 13 $ 164 Discounted cash flow Forward prices $12.56 - $148.30 / 35.52 (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 instruments for the three months ended March 31, 2021 and 2020: Price Risk Management Instruments (in millions) 2021 2020 Asset balance as of January 1 $ (72) $ 5 Net realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts (1) (22) (10) Asset (liability) balance as of March 31 $ (94) $ (5) (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Carrying Amount and Fair Value of Financial Instruments	The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At March 31, 2021 At December 31, 2020 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 5) PG&E Corporation $ 3,372 $ 2,118 $ 1,901 $ 2,175 Utility 32,056 33,200 29,664 32,632
Schedule of Unrealized Gains (Losses) Related to Available-For-Sale Investments	The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Total Unrealized Gains Total Unrealized Losses Total Fair As of March 31, 2021 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 527 1,963 (2) 2,488 Fixed-income securities 1,689 94 (18) 1,765 Total (1) $ 2,245 $ 2,057 $ (20) $ 4,282 As of December 31, 2020 Nuclear decommissioning trusts Short-term investments $ 27 $ — $ — $ 27 Global equity securities 543 1,881 (1) 2,423 Fixed-income securities 1,610 152 (3) 1,759 Total (1) $ 2,180 $ 2,033 $ (4) $ 4,209 (1) Represents amounts before deducting $690 million and $671 million for the periods ended March 31, 2021 and December 31, 2020, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Maturities on Debt Instruments	The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) March 31, 2021 Less than 1 year $ 32 1–5 years 501 5–10 years 427 More than 10 years 805 Total maturities of fixed-income securities $ 1,765
Schedule of Activity for Debt and Equity Securities	The following table provides a summary of activity for fixed income and equity securities: Three Months Ended March 31, (in millions) 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 551 $ 533 Gross realized gains on securities 55 18 Gross realized losses on securities (13) (9)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Insurance Receivable	The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: Insurance Receivable (in millions) 2020 Zogg fire 2019 Kincade fire 2017 Northern California wildfires Total Balance at December 31, 2020 $ 219 $ 430 $ 25 $ 674 Accrued insurance recoveries 28 — — 28 Reimbursements — — — — Balance at March 31, 2021 $ 247 $ 430 $ 25 $ 702

OTHER CONTINGENCIES AND COMMI_2

OTHER CONTINGENCIES AND COMMITMENTS (Tables)	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Expense and Capital Expenditures	The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.625 billion of the disallowed costs through March 31, 2021. (in millions) Description (1) Expense Capital Total Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA) $ 236 $ — $ 236 Transmission Safety Inspections and Repairs Expense (TO) (2) 433 — 433 Vegetation Management Support Costs (FHPMA) 36 — 36 2017 Northern California Wildfires CEMA Expense and Capital (CEMA) 82 66 148 2018 Camp Fire CEMA Expense (CEMA) 435 — 435 2018 Camp Fire CEMA Capital for Restoration (CEMA) — 253 253 2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA) — 84 84 Total $ 1,222 $ 403 $ 1,625 (1) All amounts included in the table reflect actual recorded costs for 2019 and 2020.
Schedule of Environmental Loss Contingencies by Site	The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following: Balance at (in millions) March 31, 2021 December 31, 2020 Topock natural gas compressor station $ 298 $ 303 Hinkley natural gas compressor station 130 132 Former manufactured gas plant sites owned by the Utility or third parties (1) 693 659 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 116 111 Fossil fuel-fired generation facilities and sites (3) 76 96 Total environmental remediation liability $ 1,313 $ 1,301 (1) Primarily driven by the following sites: San Francisco Beach Street, Vallejo, Napa, and San Francisco East Harbor. (2) Primarily driven by Geothermal landfill and Shell Pond site.

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Details)	3 Months Ended
	Mar. 31, 2021numberOfSegment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

BANKRUPTCY FILING (Chapter 11 C

BANKRUPTCY FILING (Chapter 11 Claims Process) (Details) $ in Millions	Oct. 27, 2020	Mar. 31, 2021USD ($)claim	Dec. 31, 2020USD ($)
Debt Instrument [Line Items]
Proofs of claims		100,000
Disputed claims and customer refunds | $		$ 244	$ 242
Deadline extension period	180 days
Subrogation Wildfire Trust and Fire Victim Trust
Debt Instrument [Line Items]
Proofs of claims		80,000

BANKRUPTCY FILING (Reorganizati

BANKRUPTCY FILING (Reorganization Items, Net) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Pacific Gas & Electric Co (Utility)
Debt Instrument [Line Items]
Payments (refunds) for reorganization items	$ 17	$ 117
PG&E Corporation
Debt Instrument [Line Items]
Payments (refunds) for reorganization items	$ 29	$ 57

BANKRUPTCY FILING (Schedule of

BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Reorganizations [Line Items]
Debtor-in-possession financing costs	$ 0	$ 3
Legal and other	3	179
Other	(3)
Interest income		(6)
Total reorganization items, net	0	176
PG&E Corporation
Reorganizations [Line Items]
Debtor-in-possession financing costs	0	0
Legal and other	(2)	84
Other	0
Interest income		(1)
Total reorganization items, net	(2)	83
Utility
Reorganizations [Line Items]
Debtor-in-possession financing costs	0	3
Legal and other	5	95
Other	(3)
Interest income		(5)
Total reorganization items, net	$ 2	$ 93

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Variable Interest Entities) (Details) - USD ($)	Mar. 31, 2021	Dec. 31, 2020
Debt [Line Items]
Long-term debt, gross	$ 2,150,000,000
Receivables Securitization Program | PG&E AR Facility, LLC
Debt [Line Items]
Accounts Receivable from Securitization	2,500,000,000	$ 2,600,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Aggregate maximum amount of loans made by lenders	1,000,000,000
Long-term debt, gross	$ 650,000,000	$ 1,000,000,000

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 147	$ 132
Interest cost	161	178
Expected return on plan assets	(261)	(261)
Amortization of prior service cost	(1)	(1)
Amortization of net actuarial loss	1	1
Net periodic benefit cost	47	49
Regulatory account transfer	37	34
Total	84	83
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	16	15
Interest cost	13	16
Expected return on plan assets	(35)	(34)
Amortization of prior service cost	4	3
Amortization of net actuarial loss	(8)	(5)
Net periodic benefit cost	(10)	(5)
Regulatory account transfer	0	0
Total	$ (10)	$ (5)

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	$ 21,253	$ 5,388
Net current period other comprehensive gain (loss)	1	0
Ending balance	21,379	5,759
Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	1	0
Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	0
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(22)	(5)
Ending balance	(21)	(5)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(39)	(22)
Ending balance	(38)	(22)
Accumulated Other Comprehensive Income (Loss) | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	17	17
Ending balance	17	17
Amortization of prior service cost
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	1
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	(1)	(1)
Amount attributable to tax	0	0
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	3	2
Amount attributable to tax	1	1
Amortization of net actuarial loss
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(5)	(2)
Amortization of net actuarial loss | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	1
Amount attributable to tax	0	0
Amortization of net actuarial loss | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(6)	(3)
Amount attributable to tax	2	2
Regulatory account transfer
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	4	1
Regulatory account transfer | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	0
Amount attributable to tax	0	0
Regulatory account transfer | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	3	1
Amount attributable to tax	$ 1	$ 1

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Accounting Policies [Abstract]
Period for probable revenue recovery	24 months
Pacific Gas & Electric Co (Utility)
Revenue from contracts with customers
Total operating revenues	$ 4,716	$ 4,306
Pacific Gas & Electric Co (Utility) | Electric
Revenue from contracts with customers
Total revenue from contracts with customers	2,909	2,664
Regulatory balancing accounts	486	376
Total operating revenues	3,395	3,040
Pacific Gas & Electric Co (Utility) | Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,464	1,242
Pacific Gas & Electric Co (Utility) | Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,013	1,007
Pacific Gas & Electric Co (Utility) | Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	327	341
Pacific Gas & Electric Co (Utility) | Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	152	123
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	17	17
Pacific Gas & Electric Co (Utility) | Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	(64)	(66)
Pacific Gas & Electric Co (Utility) | Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	1,732	1,626
Regulatory balancing accounts	(411)	(360)
Total operating revenues	1,321	1,266
Pacific Gas & Electric Co (Utility) | Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,208	1,066
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	245	234
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	326	348
Pacific Gas & Electric Co (Utility) | Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ (47)	$ (22)

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Wildfire Fund) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)contribution	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)	Jul. 12, 2019USD ($)
Loss Contingencies [Line Items]
Expected capitalization, proceeds of bond	$ 10,500			$ 10,500
Expected capitalization, initial contribution	7,500			7,500
Expected capitalization, annual contribution	$ 300			$ 300
Expected wildfire fund allocation metric, percentage	64.20%
Expected wildfire fund allocation metric, initial contribution	$ 4,800
Expected wildfire fund allocation metric, annual contributions	193
Initial contribution payment	4,800
Annual contribution, first payment	193
Annual contribution, second payment	$ 193
Number of remaining annual contributions | contribution	8
Litgation liability, current	$ 193
Wildfire fund, current asset	464		$ 464
Wildfire fund, noncurrent asset	5,700		5,816
Wildfire Fund expense	$ 119	$ 0
Monte carlo simulation, historical data, period	12 years
Amortization period	6 years
Percentage assumption change	10.00%
Greater effectiveness, amortization period	17 years
Less effectiveness, amortization period	12 years
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Wildfire fund, current asset	$ 464		464
Wildfire fund, noncurrent asset	5,700		$ 5,816
Wildfire Fund expense	$ 119	$ 0
5 year period
Loss Contingencies [Line Items]
Historical data period	5 years
Average annual statewide claims or settlements	$ 6,500
12 year period
Loss Contingencies [Line Items]
Historical data period	12 years
Average annual statewide claims or settlements	$ 2,900
Wildfire Fund asset
Loss Contingencies [Line Items]
Finite-lived intangible asset, useful life	15 years
Noncurrent liabilities – other
Loss Contingencies [Line Items]
Wildfire fund, noncurrent	$ 1,300

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Credit Losses) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit loss	$ 76
COVID-19 pandemic protection memorandum account
Financing Receivable, Allowance for Credit Loss [Line Items]
Regulatory assets, probable recovery	49
Federal Energy Regulatory Commission (FERC)
Financing Receivable, Allowance for Credit Loss [Line Items]
Regulatory assets, probable recovery	$ 7

SUMMARY OF SIGNIFICANT ACCOU_10

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Sale of Transmission Tower Wireless Licenses) (Details) $ in Millions	Feb. 16, 2021USD ($)transmissionTower
Public Utility, Property, Plant and Equipment [Line Items]
Proceeds from contract liability	$ 106
Pacific Gas & Electric Co (Utility) | SBA Communications Corporation | Wireless Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Duration of contract	100 years
Other tower, duration of contract	15 years
Proceeds from sale of transmission tower license	$ 973
Proceeds from sale of transmission tower license, closing	946
Proceeds from financing obligation	365
Proceeds from regulatory liabilities, current	475
Proceeds from regulatory liabilities, noncurrent	$ 471
Pacific Gas & Electric Co (Utility) | SBA Communications Corporation | Minimum | Effective Date Towers | Wireless Licenses
Public Utility, Property, Plant and Equipment [Line Items]
Number of electric transmission towers | transmissionTower	700
Number of other electric transmission towers | transmissionTower	28,000

REGULATORY ASSETS, LIABILITIE_3

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	3 Months Ended	15 Months Ended
	Mar. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 9,159	$ 9,159	$ 8,978
Retained generation asset costs	1,200	1,200
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,208	2,208	2,245
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,038	1,038	1,112
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	168	168	181
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	228	228	204
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	46	46	49
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	879	879	842
Catastrophic event memorandum account | COVID-19
Regulatory Assets [Line Items]
Total long-term regulatory assets	54	54
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	393	393	400
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	107	107	137
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	58	58	66
Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	359	359	390
Deferred income taxes
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,075	1,075	908
Insurance premium costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	225	225	294
Wildfire mitigation balancing account
Regulatory Assets [Line Items]
Total long-term regulatory assets	156	$ 156	156
Wildfire mitigation balancing account | Minimum
Regulatory Assets [Line Items]
Cost percentage threshold requiring approval		115.00%
General rate case memorandum accounts
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 349	$ 349	376
Recovery period	22 months
Vegetation management balancing account
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 594	594	592
Vegetation management balancing account | Minimum
Regulatory Assets [Line Items]
Cost percentage threshold requiring approval	120.00%
COVID-19 pandemic protection memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 132	132	84
COVID-19 pandemic protection memorandum account, undercollection bad debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	122	122
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	10	10
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 1,144	$ 1,144	$ 942

REGULATORY ASSETS, LIABILITIE_4

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 11,204	$ 10,424
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	471
Federal Energy Regulatory Commission (FERC)
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	333
California Public Utilities Commission (CPUC)
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	138
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	7,035	6,905
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	452	458
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	983	948
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	1,002	995
Tower Licenses
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	471	0
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,261	$ 1,118

REGULATORY ASSETS, LIABILITIE_5

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,368	$ 1,245
Total regulatory balancing accounts payable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	55
Total regulatory balancing accounts payable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	260	267
Total regulatory balancing accounts payable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	280	76
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	116	158
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	372	410
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	340	279
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	2,249	2,001
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	266	0
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	3	102
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	346	413
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	309	292
Total regulatory balancing accounts receivable | Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	121	121
Total regulatory balancing accounts receivable | Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	33	33
Total regulatory balancing accounts receivable | Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	161	161
Total regulatory balancing accounts receivable | Wildfire mitigation balancing account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	29	27
Total regulatory balancing accounts receivable | General rate case memorandum accounts
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	468	313
Total regulatory balancing accounts receivable | Vegetation management balancing account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	49	115
Total regulatory balancing accounts receivable | Insurance premium costs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	157	135
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 307	$ 289

DEBT (Credit Facility) (Details

DEBT (Credit Facility) (Details) - USD ($)	Mar. 11, 2021	Apr. 22, 2021	Mar. 31, 2021	Dec. 31, 2020
Debt [Line Items]
Aggregate Limit			$ 6,500,000,000
Borrowings Outstanding			2,150,000,000
Letters of Credit Outstanding			979,000,000
Facility Availability			3,371,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Aggregate Limit			500,000,000
Borrowings Outstanding			0
Letters of Credit Outstanding			0
Facility Availability			500,000,000
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Aggregate Limit			3,500,000,000
Borrowings Outstanding			0
Letters of Credit Outstanding			979,000,000
Facility Availability			2,521,000,000
Letter of credit sublimit			1,500,000,000
Term Loan, January 2022 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Aggregate Limit			1,500,000,000
Borrowings Outstanding			1,500,000,000
Letters of Credit Outstanding			0
Facility Availability			0
Term Loan, June 2021 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of debt	$ 1,500,000,000
Receivables Securitization Program | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Aggregate Limit			1,000,000,000
Borrowings Outstanding			650,000,000	$ 1,000,000,000
Letters of Credit Outstanding			0
Facility Availability			$ 350,000,000
Receivables Securitization Program | PG&E AR Facility, LLC | Subsequent event
Debt [Line Items]
Borrowings Outstanding		$ 888,000,000

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($)	Feb. 01, 2021	Jan. 31, 2021	Mar. 31, 2021	Jun. 23, 2020
First Mortgage Bonds, Exchange Stated Maturity 2023 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount			$ 1,500,000,000
Stated interest rate			1.367%
First Mortgage Bonds, Exchange Stated Maturity 2031 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount			$ 450,000,000
Stated interest rate			3.25%
First Mortgage Bonds, Exchange Stated Maturity 2041 | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Debt instrument, face amount			$ 450,000,000
Stated interest rate			4.20%
364-Day Term Loan Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Repayments of debt			$ 1,500,000,000
Debt instrument, term (in days)			364 days
Term Loan | PG&E Corporation
Debt [Line Items]
Debt instrument, face amount				$ 2,750,000,000
Debt instrument, quarterly reduction amount			$ 6,875,000
Debt instrument, basis spread on variable rate	3.00%	4.50%
Term Loan | PG&E Corporation | London Interbank Offered Rate (LIBOR)
Debt [Line Items]
Debt instrument, basis spread on variable rate	0.50%	1.00%

EQUITY (Ownership Restrictions

EQUITY (Ownership Restrictions in PG&E Corporation’s Amended Articles) (Details)	Mar. 31, 2021
PG&E Corporation | Minimum
Schedule Of Changes In Equity [Line Items]
Percentage of equity security ownership with board of director approval	4.75%

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share [Abstract]
Income attributable to common shareholders	$ 120	$ 371
Weighted average common shares outstanding, basic (in shares)	1,985	529
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	5	0
Equity Units (in shares)	141	119
Weighted average common shares outstanding, diluted (in shares)	2,131	648
Total Income per common share, diluted (in dollars per share)	$ 0.06	$ 0.57

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Mar. 31, 2021MWhMMBTU	Dec. 31, 2020MMBTUMWh
Forwards, Futures and Swaps | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	219,348,075	146,642,863
Forwards, Futures and Swaps | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	11,127,600	9,435,830
Options | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	17,080,000	14,140,000
Options | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	588,800	0
Congestion Revenue Rights | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	264,206,953	266,091,470

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ (83)	$ (73)
Derivative Asset, Netting	0	0
Cash Collateral	125	140
Total Derivative Balance, Assets	42	67
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	50	33
Derivative Asset, Netting	(3)	0
Cash Collateral	105	115
Total Derivative Balance, Assets	152	148
Noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	136	136
Derivative Asset, Netting	0	0
Cash Collateral	0	0
Total Derivative Balance, Assets	136	136
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(41)	(38)
Derivative Liability, Netting	3	0
Cash Collateral	17	15
Total Derivative Balance, Liabilities	(21)	(23)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(228)	(204)
Derivative Liability, Netting	0	0
Cash Collateral	3	10
Total Derivative Balance, Liabilities	$ (225)	$ (194)

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Assets:
Short-term investments	$ 228	$ 470
Price risk management instruments, netting	102	115
Price risk management instruments, assets	288	284
TOTAL ASSETS	5,139	5,315
Liabilities:
Price risk management instruments, netting	(23)	(25)
TOTAL LIABILITIES	246	217
Amount primarily related to deferred taxes on appreciation of investment value	690	671
Nuclear decommissioning trusts
Assets:
Short-term investments	29	27
Global equity securities	2,461	2,398
Fixed-income securities	1,765	1,759
TOTAL ASSETS	4,282	4,209
Rabbi trusts
Assets:
Fixed-income securities	102	106
Life insurance contracts	76	79
TOTAL ASSETS	178	185
Long-term disability trust
Assets:
Short-term investments	5	9
TOTAL ASSETS	163	167
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	1	2
Price risk management instruments, assets	183	170
Liabilities:
Price risk management instruments, netting	(20)	(25)
Price risk management instruments, liabilities	244	214
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	101	113
Price risk management instruments, assets	105	114
Liabilities:
Price risk management instruments, netting	(3)	0
Price risk management instruments, liabilities	2	3
Level 1
Assets:
Short-term investments	228	470
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	3,676	3,828
Liabilities:
TOTAL LIABILITIES	0	0
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	29	27
Global equity securities	2,461	2,398
Fixed-income securities	953	924
TOTAL ASSETS	3,443	3,349
Level 1 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 1 | Long-term disability trust
Assets:
Short-term investments	5	9
TOTAL ASSETS	5	9
Level 1 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 1 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 2
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	21	3
TOTAL ASSETS	1,011	1,023
Liabilities:
TOTAL LIABILITIES	10	4
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	812	835
TOTAL ASSETS	812	835
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	102	106
Life insurance contracts	76	79
TOTAL ASSETS	178	185
Level 2 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 2 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	17	2
Liabilities:
Price risk management instruments, gross subject to netting	5	1
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	4	1
Liabilities:
Price risk management instruments, gross subject to netting	5	3
Level 3
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	165	166
TOTAL ASSETS	165	166
Liabilities:
TOTAL LIABILITIES	259	238
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 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 3 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 3 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	165	166
Liabilities:
Price risk management instruments, gross subject to netting	259	238
Level 3 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Assets measured at NAV | Nuclear decommissioning trusts
Assets:
Assets measured at NAV	27	25
Assets measured at NAV | Long-term disability trust
Assets:
Assets measured at NAV	$ 158	$ 158

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021USD ($)$ / MWh	Dec. 31, 2020USD ($)$ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 5,139	$ 5,315
Liabilities | $	246	217
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	148	153
Liabilities | $	$ 79	$ 74
Market approach | Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	(320.25)	(320.25)
Market approach | Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	320.25	320.25
Market approach | Congestion revenue rights | Weighted Average Price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	0.27	0.3
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 17	$ 13
Liabilities | $	$ 180	$ 164
Discounted cash flow | Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	13.43	12.56
Discounted cash flow | Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	233.55	148.30
Discounted cash flow | Power purchase agreements | Weighted Average Price
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	39.56	35.52

FAIR VALUE MEASUREMENTS (Leve_2

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset (liability) balance	$ (72)	$ 5
Net Realized and Unrealized Gains (Losses) [Abstract]
Included in regulatory assets and liabilities or balancing accounts	(22)	(10)
Ending asset (liability) balance	$ (94)	$ (5)

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 3,372	$ 1,901
Carrying Amount | Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	32,056	29,664
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	2,118	2,175
Fair Value | Utility | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 33,200	$ 32,632

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 2,245	$ 2,180
Total Unrealized Gains	2,057	2,033
Total Unrealized Losses	(20)	(4)
Total Fair Value	4,282	4,209
Amount primarily related to deferred taxes on appreciation of investment value	690	671
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	29	27
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	29	27
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	527	543
Total Unrealized Gains	1,963	1,881
Total Unrealized Losses	(2)	(1)
Total Fair Value	2,488	2,423
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,689	1,610
Total Unrealized Gains	94	152
Total Unrealized Losses	(18)	(3)
Total Fair Value	$ 1,765	$ 1,759

FAIR VALUE MEASUREMENTS (Sche_2

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Total fair value	$ 4,282	$ 4,209
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	32
1–5 years	501
5–10 years	427
More than 10 years	805
Total fair value	$ 1,765	$ 1,759

FAIR VALUE MEASUREMENTS (Sche_3

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 551	$ 533
Gross realized gains on securities	55	18
Gross realized losses on securities	$ (13)	$ (9)

WILDFIRE- RELATED CONTINGENCIES

WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details) $ in Millions	Jan. 15, 2021USD ($)	Jul. 01, 2020USD ($)	Jun. 12, 2020	Dec. 06, 2019USD ($)
Loss Contingencies [Line Items]
Plan of reorganization, future tax benefits payment agreement		$ 1,350
Payment of plan of reorganization, future tax benefits payment agreement	$ 758
Plan of reorganization, future tax benefits payment agreement, remaining portion to be paid	$ 592
Minimum
Loss Contingencies [Line Items]
Plan of reorganization, tax benefits payment agreement		$ 650
Fire Victim Trust
Loss Contingencies [Line Items]
Percentage of common stock owned, Fire Victim Trust if common issues additional shares			22.19%
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Cash				$ 1,350
Multiplier, normalized estimated net income				14.9
Number of fully diluted shares of the reorganized, perent				20.90%
Pacific Gas & Electric Co (Utility) | Effective Date
Loss Contingencies [Line Items]
Cash contribution by company				$ 5,400
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2021
Loss Contingencies [Line Items]
Cash				758
Pacific Gas & Electric Co (Utility) | On Or Before January 15, 2022
Loss Contingencies [Line Items]
Cash				$ 592

WILDFIRE-RELATED CONTINGENCIE_2

WILDFIRE-RELATED CONTINGENCIES (2019 Kincade Fire and 2020 Zogg Fire) (Details) $ in Millions	Nov. 04, 2019numberOfPeople	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Apr. 28, 2021complaintnumberOfPlaintiffplaintiffcivil_case	Apr. 06, 2021felonymisdemeanorminorfirefighter_structure	Sep. 27, 2020astructurefatalityinjury	Oct. 23, 2019ainjurystructurenumberOfFatalitycustomer
Loss Contingencies [Line Items]
Insurance settlements receivable		$ 702	$ 674
Cumulative reimbursements from insurance policies		28
2019 Kincade Fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a							77,758
Number of fatalities (fatality) | numberOfFatality							0
Number of injuries (injuries) | injury							4
Number of structures destroyed (structure) | structure							374
Number of residences destroyed (residence) | structure							174
Number of commercial structures destroyed (structure) | structure							11
Number of other buildings destroyed (structures) | structure							189
Number of structures damaged (structure) | structure							60
Number of residential structures damaged (structure) | structure							35
Number of commercial structures damaged (structure) | structure							1
Number of other structures damaged (structure) | structure							24
Number of people part of mandatory evacuation order (people) | numberOfPeople	200,000
Number of customers without power (customer) | customer							27,837
Potential loss contingency		800	625
Potential loss contingency, additional		175
Insurance settlements receivable		430	430
Cumulative reimbursements from insurance policies		0
2019 Kincade Fire | Subsequent event
Loss Contingencies [Line Items]
Number of complaint (complaint) | complaint				25
Number of plaintiffs represented by complaints (plaintiff) | plaintiff				535
2019 Kincade Fire | Subsequent event | Sonoma Contry District Attorney | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Number of felonies (felony) | felony					5
Number of misdemeanors (misdemeanor) | misdemeanor					28
Number of felonies counts of recklessly causing a fire (felony) | felony					3
Number of firefighters and/or burned inhabited and other structures (firefighter/structure) | firefighter_structure					6
Number of felonies counts of emission of air contaminants (felony) | felony					2
Number of minors (minor) | minor					2
Number of misdemeanors related to carelessly or negligently throwing or placing substances that may cause a fire (misdemeanor) | misdemeanor					1
Number of misdemeanors related to negligently causing a fire (misdemeanor) | misdemeanor					1
Number of misdemeanors related to violation by a public utility (misdemeanor) | misdemeanor					3
Number of misdemeanors related to recklessly or negligently emitting air contaminants (misdemeanor) | misdemeanor					23
2020 Zogg Fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a						56,338
Number of fatalities (fatality) | fatality						4
Number of injuries (injuries) | injury						1
Number of structures destroyed (structure) | structure						204
Number of structures damaged (structure) | structure						27
Potential loss contingency		300	275
Potential loss contingency, additional		25
Liability insurance coverage		611
Insurance settlements receivable		247	219
Number of single family homes destroyed (structure) | structure						63
Cumulative reimbursements from insurance policies		28
Initial self-insured retention per occurrence		60
Legal fees		$ 7
2020 Zogg Fire | Maximum
Loss Contingencies [Line Items]
Liability insurance coverage			$ 867.5
2020 Zogg Fire | Subsequent event
Loss Contingencies [Line Items]
Number of complaint (complaint) | complaint				7
Number of plaintiffs represented by complaints (plaintiff) | numberOfPlaintiff				266
Number of civil cases (civil case) | civil_case				5

WILDFIRE-RELATED CONTINGENCIE_3

WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions	Apr. 29, 2021	Mar. 31, 2021	Aug. 31, 2020
Loss Contingencies [Line Items]
Prepaid Insurance		$ 313
Insurance premium costs, recovery, coverage amount		1,400
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Initial self-insured retention per occurrence		60
Insurance Coverage for Wildfire Events | April 12, 2021 to April 1, 2022 | Subsequent event
Loss Contingencies [Line Items]
Liability insurance coverage	$ 268
Reinsurance	32
Costs for insurance coverage	$ 220
Insurance Coverage for Wildfire Events | July 1, 2020 to July 1, 2021
Loss Contingencies [Line Items]
Reinsurance			$ 11
Insurance Coverage for Wildfire Events | August 1, 2020 to August 1, 2021
Loss Contingencies [Line Items]
Liability insurance coverage			$ 600
Insurance Coverage for Wildfire Events | August 1, 2021 to August 1, 2022
Loss Contingencies [Line Items]
Costs for insurance coverage		516
Insurance Coverage For Non-Wildfire Events | August 1, 2020 to August 1, 2021
Loss Contingencies [Line Items]
Liability insurance coverage		700
Costs for insurance coverage		$ 152

WILDFIRE-RELATED CONTINGENCIE_4

WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	$ 674
Accrued insurance recoveries	28
Reimbursements	0
Insurance Receivable, ending balance	702
2020 Zogg Fire
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	219
Accrued insurance recoveries	28
Reimbursements	0
Insurance Receivable, ending balance	247
2019 Kincade Fire
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	430
Accrued insurance recoveries	0
Reimbursements	0
Insurance Receivable, ending balance	430
2017 Northern California wildfires
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	25
Accrued insurance recoveries	0
Reimbursements	0
Insurance Receivable, ending balance	$ 25

WILDFIRE-RELATED CONTINGENCIE_5

WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2017 Northern California wildfires - USD ($) $ in Millions	Mar. 23, 2021	Apr. 30, 2020
Loss Contingencies [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized	$ 7,500	$ 7,500
Customer Harm Threshold, post-emergence transaction, debt retirement		6,000
Customer Harm Threshold, post-emergence transaction, debt payment acceleration remaining		$ 592

WILDFIRE-RELATED CONTINGENCIE_6

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details)	Mar. 30, 2021action	Feb. 24, 2021noticecomplaint	Nov. 20, 2017lawsuit	Nov. 16, 2017lawsuit
Loss Contingencies [Line Items]
Number of amended complaints (complaint) | complaint		1
Number of actions consolidated (action) | action	2
Breach of Fiduciary Duties
Loss Contingencies [Line Items]
Number of causes (cause) | notice		2
Derivative Lawsuits Filed in the San Francisco County Superior Court | Breach of Fiduciary Duties
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit			2	2

WILDFIRE-RELATED CONTINGENCIE_7

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation) (Details)	Apr. 26, 2021objection	Feb. 22, 2019offering	Dec. 31, 2018lawsuit	Jun. 30, 2018lawsuit
Wildfire-Related Class Action
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit				2
Number of public offerings of notes with complaints against underwriters (offering) | offering		4
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit			3
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt | Subsequent event
Loss Contingencies [Line Items]
Number of expunged omnibus objection (objection) | objection	2
Number of omnibus objection (objection) | objection	3

WILDFIRE-RELATED CONTINGENCIE_8

WILDFIRE-RELATED CONTINGENCIES (De-energization Class Action) (Details) - De-energization Class Action $ in Millions	Feb. 16, 2021USD ($)
Loss Contingencies [Line Items]
Litigation settlement, amount awarded from other party	$ 10
Litigation settlement, approval of settlement, escrow deposit, number of days	14 days

WILDFIRE-RELATED CONTINGENCIE_9

WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co (Utility) - Complaints Brought By Butte County District Attorney - Loss from Wildfires	Mar. 17, 2020count
Loss Contingencies [Line Items]
Number of guilty involuntary manslaughter pleas (count)	84
Number of count related to unlawfully causing a fire (count)	1

WILDFIRE-RELATED CONTINGENCI_10

WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions	Jul. 12, 2019	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Disallowance cap, transmission and distribution equity rate base	$ 2,700
Initial safety certification, period	12 months
Initial safety certification, documentation provided, period	90 days
Expected capitalization, proceeds of bond	$ 10,500	$ 10,500
Expected capitalization, initial contribution	7,500	7,500
Expected capitalization, annual contribution	300	$ 300
Allocation	$ 3,210

OTHER CONTINGENCIES AND COMMI_3

OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Narrative) (Details) $ in Millions	Mar. 31, 2021USD ($)	Jan. 04, 2021party	Jun. 08, 2020party	Apr. 20, 2020USD ($)	Dec. 17, 2019USD ($)
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed costs	$ 1,625
Expenses and capital expenditures, disallowed capital, approved				$ 198
Shareholder-funded system enhancement initiatives, approved				64
Fine payable to general fund, suspended				$ 200
Number of parties filed separate applications for rehearing (party) | party			2
Number of parties filed petition for review of decision (party) | party		1
Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Expenses and capital expenditures	1,625
Disallowed capital, approved, cumulative charge	172
Disallowed capital, approved, cumulative charge, remaining portion	$ 26
Pacific Gas & Electric Co (Utility) | Pending Litigation | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Expenses and capital expenditures					$ 1,625
Shareholder-funded system enhancement initiatives, amount					$ 50

OTHER CONTINGENCIES AND COMMI_4

OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Legal Obligation) (Details) - Pacific Gas & Electric Co (Utility) $ in Millions	Mar. 31, 2021USD ($)
Loss Contingencies [Line Items]
Expense	$ 1,222
Capital	403
Total	1,625
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)
Loss Contingencies [Line Items]
Expense	236
Capital	0
Total	236
Transmission Safety Inspections and Repairs Expense (TO)
Loss Contingencies [Line Items]
Expense	433
Capital	0
Total	433
Vegetation Management Support Costs (FHPMA)
Loss Contingencies [Line Items]
Expense	36
Capital	0
Total	36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)
Loss Contingencies [Line Items]
Expense	82
Capital	66
Total	148
2018 Camp Fire CEMA Expense (CEMA)
Loss Contingencies [Line Items]
Expense	435
Capital	0
Total	435
2018 Camp Fire CEMA Capital for Restoration (CEMA)
Loss Contingencies [Line Items]
Expense	0
Capital	253
Total	253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)
Loss Contingencies [Line Items]
Expense	0
Capital	84
Total	$ 84

OTHER CONTINGENCIES AND COMMI_5

OTHER CONTINGENCIES AND COMMITMENTS (Transmission Owner Rate) (Details) $ in Millions	Sep. 21, 2018	Apr. 15, 2021USD ($)party	May 21, 2020
Transmission Owner Rate Case Revenue
Loss Contingencies [Line Items]
Approved depreciation rate			2.94%
Requested depreciation rate			3.25%
Labor rates, allocation percentage			6.15%
Direct assignment, percentage			8.84%
Subsequent event | Transmission Owner Rate Case Revenue
Loss Contingencies [Line Items]
Regulatory liabilities		$ 270
Regulatory assets		$ 150
Pacific Gas & Electric Co (Utility) | Subsequent event | Transmission Owner Rate Case Revenue
Loss Contingencies [Line Items]
Number of parties granted for rehearing related to Tax Act | party		2
Pacific Gas & Electric Co (Utility) | Electric
Loss Contingencies [Line Items]
Requested revenue rate	98.85%

OTHER CONTINGENCIES AND COMMI_6

OTHER CONTINGENCIES AND COMMITMENTS (Interim Rate Relief Subject to Refund) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)	Jan. 08, 2021USD ($)	Sep. 30, 2020USD ($)	May 04, 2020USD ($)	Mar. 31, 2020catastrophicEvent	Aug. 07, 2019USD ($)	Apr. 25, 2019USD ($)	Mar. 31, 2018USD ($)catastrophicEvent
Loss Contingencies [Line Items]
Expenses and capital expenditures, disallowed costs	$ 1,625
CEMA Interim Rate Relief
Loss Contingencies [Line Items]
Cost recovery							$ 373
Revised cost recovery, increase to revenue requirement		$ 5.6		$ 757		$ 669
CEMA Interim Rate Relief | Mid 2016 - Early 2017
Loss Contingencies [Line Items]
Cost recovery								$ 183
Number of catastrophic events | catastrophicEvent								7
CEMA Interim Rate Relief | 2016 to 2017
Loss Contingencies [Line Items]
Cost recovery								$ 405
WMCE Interim Rate Relief
Loss Contingencies [Line Items]
Number of catastrophic events | catastrophicEvent					10
Expenses and capital expenditures, disallowed costs			$ 1,180
Expenses and capital expenditures, capital expenditures			801
Cost recovery, increase to revenue requirement			$ 1,280
Approved interim rate relief	447
Interim rate relief remaining	$ 868
Interim rate relief remaining, period	1 year
Approved interim rate relief, subject to refund	$ 447
WMCE Interim Rate Relief | Fire hazard prevention memorandum account
Loss Contingencies [Line Items]
Cost recovery	293
WMCE Interim Rate Relief | Fire risk and wildfire mitigation memorandum account
Loss Contingencies [Line Items]
Cost recovery	740
WMCE Interim Rate Relief | Catastrophic event memorandum account
Loss Contingencies [Line Items]
Cost recovery	$ 251

OTHER CONTINGENCIES AND COMMI_7

OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Accrued legal liabilities	$ 134	$ 144

OTHER CONTINGENCIES AND COMMI_8

OTHER CONTINGENCIES AND COMMITMENTS (PSPS Class Action) (Details) $ in Billions	Dec. 19, 2019USD ($)
PSPS Class Action | Pending Litigation | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Loss contingency, damages sought	$ 2.5

OTHER CONTINGENCIES AND COMMI_9

OTHER CONTINGENCIES AND COMMITMENTS (GT&S Capital Expenditures) (Details) - Disallowance of Plant Costs - USD ($) $ in Millions	Jun. 23, 2016	Jun. 30, 2020	Nov. 10, 2020	Jul. 31, 2020	Jun. 01, 2020
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance	$ 696
Permanently disallowed capital	$ 120
Amount subject to audit		$ 576
Capital expenditures for future recovery				$ 512	$ 512
Loss Contingency, Interim Rate Request Amount			$ 100

OTHER CONTINGENCIES AND COMM_10

OTHER CONTINGENCIES AND COMMITMENTS (CZU Lightning Complex Fire Notice of Violations) (Details)	3 Months Ended
	Apr. 07, 2021notice
CZU Lightning Complex Fire Notice of Violations | Subsequent event
Loss Contingencies [Line Items]
Number of notices issued of violation (notice)	6

OTHER CONTINGENCIES AND COMM_11

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Liability) (Details) - USD ($) $ in Millions	Mar. 31, 2021	Dec. 31, 2020
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]
Topock natural gas compressor station	$ 298	$ 303
Hinkley natural gas compressor station	130	132
Former manufactured gas plant sites owned by the Utility or third parties	693	659
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	116	111
Fossil fuel-fired generation facilities and sites	76	96
Environmental Remediation Liability	$ 1,313	$ 1,301

OTHER CONTINGENCIES AND COMM_12

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Mar. 31, 2021USD ($)
Commitments and Contingencies Disclosure [Abstract]
Amount of environmental loss accrual expected to be recovered	$ 1,017

OTHER CONTINGENCIES AND COMM_13

OTHER CONTINGENCIES AND COMMITMENTS (Station Sites, Gas Plants, Generation Facilities and Disposal Sites) (Details) $ in Millions	Mar. 31, 2021USD ($)
Topock Site
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 220
Topock Site | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 138
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 436
Remediation cost recovery percentage	90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 59
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co (Utility)
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 44

OTHER CONTINGENCIES AND COMM_14

OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance and Diablo Canyon Outages) (Details)	3 Months Ended	10 Months Ended
	Mar. 31, 2021USD ($)nuclear_generating_unit	Apr. 29, 2021outage
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Nuclear Electric Insurance Limited and European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Insurance coverage, loss	$ 400,000,000
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	42,000,000
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Additional insurance coverage, loss	200,000,000
Amount of property damage coverage provided by NEIL	4,000,000
Diablo Canyon Outage | Subsequent event
Long-term Purchase Commitment [Line Items]
Number of outages experienced (outage) | outage		5
Property damage and business interruption coverage | Humboldt Bay Unit 3 | Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Liability insurance coverage	50,000,000
Property damage and business interruption coverage, nuclear incident | Diablo Canyon | Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Liability insurance coverage	3,200,000,000
Property damage and business interruption coverage, non-nuclear incident | Diablo Canyon | Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Liability insurance coverage	$ 2,500,000,000

OTHER CONTINGENCIES AND COMM_15

OTHER CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Billions	Dec. 31, 2020USD ($)
Commitments and Contingencies Disclosure [Abstract]
Recorded unconditional purchase obligation	$ 35

OTHER CONTINGENCIES AND COMM_16

OTHER CONTINGENCIES AND COMMITMENTS (Oakland Headquarters Lease) (Details) ft² in Thousands, $ in Millions	Oct. 23, 2020USD ($)	Jun. 05, 2020USD ($)ft²
Commitments and Contingencies Disclosure [Abstract]
Rentable square feet (sqft) | ft²		910
Lease, option payment letter of credit	$ 75
Lease, security letter of credit	$ 75
Term of contract		34 years 11 months
Purchase options, land, value		$ 892