PG&E (PCG) 10-Q 29 Jul 21 2021 Q2 Quarterly report Financial data

Cover

Cover - shares	6 Months Ended
	Jun. 30, 2021	Jul. 26, 2021
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 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)		2,463,016,638
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
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
PG&E ShareCo LLC
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding (in shares)		477,743,590
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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating Revenues
Total operating revenues	$ 5,215	$ 4,533	$ 9,931	$ 8,839
Operating Expenses
Operating and maintenance	2,583	2,141	4,919	4,108
Wildfire-related claims, net of insurance recoveries	(5)	170	167	170
Wildfire Fund expense	118	173	237	173
Depreciation, amortization, and decommissioning	851	874	1,739	1,729
Total operating expenses	4,581	4,251	8,993	7,902
Operating Income	634	282	938	937
Interest income	15	12	17	28
Interest expense	(398)	(199)	(806)	(453)
Other income, net	128	100	255	197
Reorganization items, net	(11)	(1,624)	(11)	(1,800)
Income (Loss) Before Income Taxes	368	(1,429)	393	(1,091)
Income tax provision (benefit)	(33)	539	(131)	503
Net Income (Loss)	401	(1,968)	524	(1,594)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Income (Loss) Attributable to Common Shareholders	$ 397	$ (1,972)	$ 517	$ (1,601)
Weighted Average Common Shares Outstanding, Basic (in shares)	1,985	529	1,985	529
Weighted Average Common Shares Outstanding, Diluted (in shares)	2,146	529	2,146	529
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ 0.20	$ (3.73)	$ 0.26	$ (3.03)
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ 0.18	$ (3.73)	$ 0.24	$ (3.03)
Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	$ 5,215	$ 4,533	$ 9,931	$ 8,839
Operating Expenses
Operating and maintenance	2,581	2,145	4,912	4,110
Wildfire-related claims, net of insurance recoveries	(5)	170	167	170
Wildfire Fund expense	118	173	237	173
Depreciation, amortization, and decommissioning	851	874	1,739	1,729
Total operating expenses	4,579	4,255	8,986	7,904
Operating Income	636	278	945	935
Interest income	15	12	17	28
Interest expense	(342)	(189)	(690)	(441)
Other income, net	124	93	257	186
Reorganization items, net	(10)	(111)	(12)	(204)
Income (Loss) Before Income Taxes	423	83	517	504
Income tax provision (benefit)	(17)	556	(100)	526
Net Income (Loss)	440	(473)	617	(22)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Income (Loss) Attributable to Common Shareholders	436	(477)	610	(29)
Electric
Operating Revenues
Total operating revenues	3,951	3,435	7,346	6,475
Operating Expenses
Cost of goods	847	759	1,437	1,304
Electric | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	3,951	3,435	7,346	6,475
Operating Expenses
Cost of goods	847	759	1,437	1,304
Natural gas
Operating Revenues
Total operating revenues	1,264	1,098	2,585	2,364
Operating Expenses
Cost of goods	187	134	494	418
Natural gas | Pacific Gas & Electric Co (Utility)
Operating Revenues
Total operating revenues	1,264	1,098	2,585	2,364
Operating Expenses
Cost of goods	$ 187	$ 134	$ 494	$ 418

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Net Income (Loss)	$ 401	$ (1,968)	$ 524	$ (1,594)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, respectively)	0	0	1	0
Total other comprehensive income	0	0	1	0
Comprehensive Income (Loss)	401	(1,968)	525	(1,594)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Comprehensive Income (Loss) Attributable to Common Shareholders	397	(1,972)	518	(1,601)
Pacific Gas & Electric Co (Utility)
Net Income (Loss)	440	(473)	617	(22)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, respectively)	0	0	0	0
Total other comprehensive income	0	0	0	0
Comprehensive Income (Loss)	$ 440	$ (473)	$ 617	$ (22)

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Pacific Gas & Electric Co (Utility)
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 307	$ 484
Restricted cash	12	143
Accounts receivable:
Customers (net of allowance for doubtful accounts of $304 million and $146 million at respective dates) (includes $1.67 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $304 million and $143 million at respective dates)	1,909	1,883
Accrued unbilled revenue (includes $1.03 billion and $959 million related to VIEs at respective dates)	1,134	1,083
Regulatory balancing accounts	2,759	2,001
Other	1,323	1,172
Regulatory assets	622	410
Inventories:
Gas stored underground and fuel oil	44	95
Materials and supplies	521	533
Wildfire Fund asset	464	464
Other	1,194	1,334
Total current assets	10,289	9,602
Property, Plant, and Equipment
Electric	69,239	66,982
Gas	25,082	24,135
Construction work in progress	2,778	2,757
Other	20	20
Total property, plant, and equipment	97,119	93,894
Accumulated depreciation	(28,775)	(27,758)
Net property, plant, and equipment	68,344	66,136
Other Noncurrent Assets
Regulatory assets	8,914	8,978
Nuclear decommissioning trusts	3,697	3,538
Operating lease right of use asset	1,477	1,741
Wildfire Fund asset	5,584	5,816
Income taxes receivable	68	67
Other	2,121	1,978
Total other noncurrent assets	21,861	22,118
TOTAL ASSETS	100,494	97,856
Current Liabilities
Short-term borrowings	2,119	3,547
Long-term debt, classified as current	4,514	28
Accounts payable:
Trade creditors	2,250	2,402
Regulatory balancing accounts	1,067	1,245
Other	653	580
Operating lease liabilities	415	533
Interest payable	480	498
Disputed claims and customer refunds	245	242
Wildfire-related claims	1,668	2,250
Other	2,082	2,256
Total current liabilities	15,493	13,581
Noncurrent Liabilities
Long-term debt (includes $1.0 billion related to VIEs at respective dates)	35,955	37,288
Regulatory liabilities	11,218	10,424
Pension and other post-retirement benefits	2,367	2,444
Asset retirement obligations	6,554	6,412
Deferred income taxes	1,618	1,398
Operating lease liabilities	1,061	1,208
Other	4,429	3,848
Total noncurrent liabilities	63,202	63,022
Shareholders’ Equity
Common stock	30,245	30,224
Reinvested earnings	(8,672)	(9,196)
Accumulated other comprehensive loss	(26)	(27)
Total shareholders’ equity	21,547	21,001
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	21,799	21,253
TOTAL LIABILITIES AND EQUITY	100,494	97,856
Pacific Gas & Electric Co (Utility)
Current Assets
Cash and cash equivalents	233	261
Restricted cash	12	143
Accounts receivable:
Customers (net of allowance for doubtful accounts of $304 million and $146 million at respective dates) (includes $1.67 billion and $1.63 billion related to VIEs, net of allowance for doubtful accounts of $304 million and $143 million at respective dates)	1,909	1,883
Accrued unbilled revenue (includes $1.03 billion and $959 million related to VIEs at respective dates)	1,134	1,083
Regulatory balancing accounts	2,759	2,001
Other	1,324	1,180
Regulatory assets	622	410
Inventories:
Gas stored underground and fuel oil	44	95
Materials and supplies	521	533
Wildfire Fund asset	464	464
Other	1,181	1,321
Total current assets	10,203	9,374
Property, Plant, and Equipment
Electric	69,239	66,982
Gas	25,082	24,135
Construction work in progress	2,778	2,757
Other	18	18
Total property, plant, and equipment	97,117	93,892
Accumulated depreciation	(28,773)	(27,756)
Net property, plant, and equipment	68,344	66,136
Other Noncurrent Assets
Regulatory assets	8,914	8,978
Nuclear decommissioning trusts	3,697	3,538
Operating lease right of use asset	1,474	1,736
Wildfire Fund asset	5,584	5,816
Income taxes receivable	67	66
Other	1,962	1,818
Total other noncurrent assets	21,698	21,952
TOTAL ASSETS	100,245	97,462
Current Liabilities
Short-term borrowings	2,119	3,547
Long-term debt, classified as current	4,488	0
Accounts payable:
Trade creditors	2,249	2,366
Regulatory balancing accounts	1,067	1,245
Other	660	624
Operating lease liabilities	413	530
Interest payable	429	444
Disputed claims and customer refunds	245	242
Wildfire-related claims	1,668	2,250
Other	2,079	2,248
Total current liabilities	15,417	13,496
Noncurrent Liabilities
Long-term debt (includes $1.0 billion related to VIEs at respective dates)	31,361	32,664
Regulatory liabilities	11,218	10,424
Pension and other post-retirement benefits	2,256	2,328
Asset retirement obligations	6,554	6,412
Deferred income taxes	1,820	1,570
Operating lease liabilities	1,061	1,206
Other	4,465	3,886
Total noncurrent liabilities	58,735	58,490
Shareholders’ Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	28,286	28,286
Reinvested earnings	(3,768)	(4,385)
Accumulated other comprehensive loss	(5)	(5)
Total shareholders’ equity	26,093	25,476
TOTAL LIABILITIES AND EQUITY	$ 100,245	$ 97,462

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Allowance for doubtful accounts	$ 304	$ 146
Customers (net of allowance for doubtful accounts)	1,909	1,883
Accrued unbilled revenue	1,134	1,083
Long-term debt	$ 35,955	$ 37,288
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)	1,985,273,048	1,984,678,673
Variable Interest Entity
Allowance for doubtful accounts	$ 304	$ 143
Customers (net of allowance for doubtful accounts)	1,670	1,630
Accrued unbilled revenue	1,030	959
Long-term debt	1,000	1,000
Pacific Gas & Electric Co (Utility)
Allowance for doubtful accounts	304	146
Customers (net of allowance for doubtful accounts)	1,909	1,883
Accrued unbilled revenue	1,134	1,083
Long-term debt	$ 31,361	$ 32,664
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
Pacific Gas & Electric Co (Utility) | Variable Interest Entity
Allowance for doubtful accounts	$ 304	$ 143
Customers (net of allowance for doubtful accounts)	1,670	1,630
Accrued unbilled revenue	1,030	959
Long-term debt	$ 1,000	$ 1,000

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Cash Flows from Operating Activities
Net Income (Loss)	$ 524	$ (1,594)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,739	1,729
Allowance for equity funds used during construction	(61)	(21)
Deferred income taxes and tax credits, net	228	869
Reorganization items, net (Note 2)	(62)	1,558
Wildfire Fund expense	237	173
Other	385	142
Effect of changes in operating assets and liabilities:
Accounts receivable	(300)	(389)
Wildfire-related insurance receivable	(108)	99
Inventories	(1)	(19)
Accounts payable	119	722
Wildfire-related claims	(582)	619
Income taxes receivable/payable	0	0
Other current assets and liabilities	(281)	529
Regulatory assets, liabilities, and balancing accounts, net	(739)	(1,570)
Liabilities subject to compromise	0	413
Other noncurrent assets and liabilities	132	31
Net cash provided by operating activities	1,230	3,291
Cash Flows from Investing Activities
Capital expenditures	(3,620)	(3,399)
Proceeds from sales and maturities of nuclear decommissioning trust investments	952	787
Purchases of nuclear decommissioning trust investments	(948)	(837)
Other	48	8
Net cash used in investing activities	(3,568)	(3,441)
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	(73)
Borrowings under revolving credit facilities	4,432	0
Repayments under revolving credit facilities	(5,867)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $33 and $165 at respective dates	3,171	13,510
Repayment of long-term debt	(14)	0
Proceeds from sale of future revenue from transmission tower license sales, net of fees	350	0
Other	(42)	20
Net cash provided by financing activities	2,030	13,954
Net change in cash, cash equivalents, and restricted cash	(308)	13,804
Cash, cash equivalents, and restricted cash at January 1	627	1,577
Cash, cash equivalents, and restricted cash at June 30	319	15,381
Less: Restricted cash and restricted cash equivalents	(12)	(14,413)
Cash and cash equivalents	307	968
Cash paid for:
Interest, net of amounts capitalized	(702)	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	614	273
Operating lease liabilities arising from obtaining right-of-use assets	20	13
Pacific Gas & Electric Co (Utility)
Cash Flows from Operating Activities
Net Income (Loss)	617	(22)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,739	1,729
Allowance for equity funds used during construction	(61)	(21)
Deferred income taxes and tax credits, net	257	890
Reorganization items, net (Note 2)	(29)	13
Wildfire Fund expense	237	173
Other	353	138
Effect of changes in operating assets and liabilities:
Accounts receivable	(293)	(374)
Wildfire-related insurance receivable	(108)	99
Inventories	(1)	(19)
Accounts payable	84	701
Wildfire-related claims	(582)	619
Income taxes receivable/payable	0	0
Other current assets and liabilities	(272)	(4)
Regulatory assets, liabilities, and balancing accounts, net	(739)	(1,570)
Liabilities subject to compromise	0	401
Other noncurrent assets and liabilities	133	47
Net cash provided by operating activities	1,335	2,800
Cash Flows from Investing Activities
Capital expenditures	(3,620)	(3,399)
Proceeds from sales and maturities of nuclear decommissioning trust investments	952	787
Purchases of nuclear decommissioning trust investments	(948)	(837)
Other	48	8
Net cash used in investing activities	(3,568)	(3,441)
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	(33)
Borrowings under revolving credit facilities	4,432	0
Repayments under revolving credit facilities	(5,867)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $33 and $165 at respective dates	3,171	8,850
Proceeds from sale of future revenue from transmission tower license sales, net of fees	350	0
Other	(12)	20
Net cash provided by financing activities	2,074	9,334
Net change in cash, cash equivalents, and restricted cash	(159)	8,693
Cash, cash equivalents, and restricted cash at January 1	404	1,129
Cash, cash equivalents, and restricted cash at June 30	245	9,822
Less: Restricted cash and restricted cash equivalents	(12)	(9,076)
Cash and cash equivalents	233	746
Cash paid for:
Interest, net of amounts capitalized	(595)	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	614	273
Operating lease liabilities arising from obtaining right-of-use assets	$ 20	$ 13

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2021	Jun. 30, 2020
Net of discount and issuance costs	$ 33	$ 165
Pacific Gas & Electric Co (Utility)
Net of discount and issuance costs	$ 33	$ 75

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 (Loss)	374		374		374						451		451
Other comprehensive income (loss)	0			0	0
Common stock issued, net (in shares)		549,155
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, 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 (Loss)	(1,594)						$ (22)
Ending balance (in shares) at Jun. 30, 2020		529,793,355
Ending balance at Jun. 30, 2020	3,801	$ 13,045	(9,486)	(10)	3,549	252		258	1,322	8,550	(4,818)	1	5,313
Beginning balance (in shares) at Mar. 31, 2020		529,785,896
Beginning 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(1,968)		(1,968)		(1,968)		$ (473)				(473)		(473)
Other comprehensive income (loss)	0			0	0
Common stock issued, net (in shares)		7,459
Stock-based compensation amortization	10	$ 10			10
Ending balance (in shares) at Jun. 30, 2020		529,793,355
Ending balance at Jun. 30, 2020	$ 3,801	$ 13,045	(9,486)	(10)	3,549	252		258	1,322	8,550	(4,818)	1	5,313
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 (Loss)	123		123		123						177		177
Other comprehensive income (loss)	1			1	1
Common stock issued, net (in shares)		427,030
Stock-based compensation amortization	2	$ 2			2
Ending balance (in shares) at Mar. 31, 2021		1,985,105,703
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
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 (Loss)	$ 524						$ 617
Ending balance (in shares) at Jun. 30, 2021	1,985,273,048	1,985,273,048					264,374,809
Ending balance at Jun. 30, 2021	$ 21,799	$ 30,245	(8,672)	(26)	21,547	252		258	1,322	28,286	(3,768)	(5)	26,093
Beginning balance (in shares) at Mar. 31, 2021		1,985,105,703
Beginning 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	401		401		401		$ 440				440		440
Other comprehensive income (loss)	0			0	0
Common stock issued, net (in shares)		167,345
Stock-based compensation amortization	$ 19	$ 19			19
Ending balance (in shares) at Jun. 30, 2021	1,985,273,048	1,985,273,048					264,374,809
Ending balance at Jun. 30, 2021	$ 21,799	$ 30,245	$ (8,672)	$ (26)	$ 21,547	$ 252		$ 258	$ 1,322	$ 28,286	$ (3,768)	$ (5)	$ 26,093

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	6 Months Ended
	Jun. 30, 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	6 Months Ended
	Jun. 30, 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. On May 20, 2021, the FERC approved an uncontested filing that will result in a final market clearing and funds distribution associated with the issues being considered by the FERC. Upon the completion of several intervening steps, including obtaining approval of the bankruptcy courts overseeing the Utility’s prior bankruptcy proceeding as well as the bankruptcy of the California Power Exchange, the FERC will determine final amounts owed to and from the California electric IOUs. At June 30, 2021 and December 31, 2020, the Condensed Consolidated Balance Sheets reflected $245 million and $242 million, respectively, 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 on October 28, 2020, appointed a panel of mediators. The mediators’ role is 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 has been extended to October 1, 2021, November 1, 2021 or December 31, 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 $2 million and $24 million for PG&E Corporation and the Utility, respectively, during the three months ended June 30, 2021 as compared to $33 million and $90 million fo r PG&E Corporation and the Utility, respectively, during the same period in 2020. Cash paid for reorganization items, net was $31 million and $41 million for PG&E Corporation and the Utility, respectively, during the six months ended June 30, 2021 as compared to $90 million and $207 million fo r PG&E Corporation and the Utility, respectively, during the same period in 2020. Reorganization items, net for the three and six months ended June 30, 2021 and 2020 include the following: Three Months Ended June 30, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 15 1 16 Other (5) — (5) Total reorganization items, net $ 10 $ 1 $ 11 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Three Months Ended June 30, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 1 $ — $ 1 Legal and other (2) 110 1,513 1,623 Interest income — — — Total reorganization items, net $ 111 $ 1,513 $ 1,624 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense, bridge loan facility fees, and trustee fees. Six Months Ended June 30, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 21 (1) 20 Other (9) — (9) Total reorganization items, net $ 12 $ (1) $ 11 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Six Months Ended June 30, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 3 $ — $ 3 Legal and other (2) 206 1,598 1,804 Interest income (5) (2) (7) Total reorganization items, net $ 204 $ 1,596 $ 1,800 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense, bridge loan facility fees, and trustee fees.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	6 Months Ended
	Jun. 30, 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 June 30, 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 June 30, 2021 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.7 billion and $2.6 billion, respectively, and outstanding borrowings of $1.0 billion 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 June 30, 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 June 30, 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 and six months ended June 30, 2021 and 2020 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 146 $ 132 $ 16 $ 16 Interest cost 162 179 13 15 Expected return on plan assets (262) (261) (35) (35) Amortization of prior service cost (2) (2) 3 4 Amortization of net actuarial loss 2 1 (8) (5) Net periodic benefit cost 46 49 (11) (5) Regulatory account transfer (2) 37 34 — — Total $ 83 $ 83 $ (11) $ (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. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 293 $ 264 $ 32 $ 31 Interest cost 323 357 26 31 Expected return on plan assets (523) (522) (70) (69) Amortization of prior service cost (3) (3) 7 7 Amortization of net actuarial loss 3 2 (16) (10) Net periodic benefit cost 93 98 (21) (10) Regulatory account transfer (2) 74 68 — — Total $ 167 $ 166 $ (21) $ (10) (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 June 30, 2021 Beginning balance $ (38) $ 17 $ (21) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $1 and $2, respectively) 1 (6) (5) Regulatory account transfer (net of taxes of $0 and $1, respectively) — 4 4 Net current period other comprehensive gain (loss) — — — 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 Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) — (4) (4) Regulatory account transfer (net of taxes of $0 and $0, respectively) 1 1 2 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.) Pension Benefits Other Benefits Total (in millions, net of income tax) Six Months Ended June 30, 2021 Beginning balance $ (39) $ 17 $ (22) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $1 and $4, respectively) 2 (12) (10) Regulatory account transfer (net of taxes of $0 and $2, respectively) 1 7 8 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 Benefits Total (in millions, net of income tax) Six Months Ended June 30, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $1 and $3, respectively) 1 (7) (6) Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 2 3 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 have been 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 June 30, Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Electric Revenue from contracts with customers Residential $ 1,352 $ 987 $ 2,815 $ 2,230 Commercial 1,183 1,075 2,196 2,082 Industrial 305 342 632 682 Agricultural 431 368 583 491 Public street and highway lighting 18 17 35 34 Other (1) 285 269 222 203 Total revenue from contracts with customers - electric 3,574 3,058 6,483 5,722 Regulatory balancing accounts (2) 377 377 863 753 Total electric operating revenue $ 3,951 $ 3,435 $ 7,346 $ 6,475 Natural gas Revenue from contracts with customers Residential $ 418 $ 426 $ 1,626 $ 1,492 Commercial 139 110 384 344 Transportation service only 346 296 672 643 Other (1) (137) (159) (184) (180) Total revenue from contracts with customers - gas 766 673 2,498 2,299 Regulatory balancing accounts (2) 498 425 87 65 Total natural gas operating revenue 1,264 1,098 2,585 2,364 Total operating revenues $ 5,215 $ 4,533 $ 9,931 $ 8,839 (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 June 30, 2021, PG&E Corporation and the Utility have eight remaining annual contributions of $193 million (based on the current Wildfire Fund allocation metric). 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 June 30, 2021, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $1.3 billion in Other noncurrent liabilities, $464 million in current assets - Wildfire Fund asset, and $5.6 billion in noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three and six months ended June 30, 2021, the Utility recorded amortization and accretion expense of $118 million and $237 million, respectively. 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 five Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility’s electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is currently unknown, which may in the future be determined to be covered by the Wildfire Fund. At June 30, 2021, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund. 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 and six months ended June 30, 2021, expected credit losses of $113 million and $189 million, respectively, were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables. During the three and six months ended June 30, 2020, expected credit losses of $44 million, respectively, were recorded to Operating and maintenance expense on the Condensed Consolidated Statements of Income. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA and a FERC regulatory asset. At June 30, 2021, the RUBA current balancing accounts receivable balance was $182 million, and CPPMA and FERC long-term regulatory asset balances were $26 million and $26 million, 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 August 15, 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 third-party 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 noncurrent liabilities on the Condensed Consolidated Balance Sheets. The Utility recorded the remaining approximately $475 million ($471 million of which was noncurrent) of the sale proceeds to regulatory liabilities, for the portion that is probable to be returned to customers in accordance with existing revenue sharing practices. The financing obligation is amortized through Electric operating revenue and Interest expense on the Condensed Consolidated Statements of Income using the effective interest method and the deferred revenue balance is amortized 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	6 Months Ended
	Jun. 30, 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) June 30, 2021 December 31, 2020 Pension benefits (1) $ 2,172 $ 2,245 Environmental compliance costs 1,046 1,112 Utility retained generation (2) 156 181 Price risk management 160 204 Unamortized loss, net of gain, on reacquired debt 43 49 Catastrophic event memorandum account (3) 916 842 Wildfire expense memorandum account (4) 230 400 Fire hazard prevention memorandum account (5) 87 137 Fire risk mitigation memorandum account (6) 52 66 Wildfire mitigation plan memorandum account (7) 407 390 Deferred income taxes (8) 1,257 908 Insurance premium costs (9) 242 294 Wildfire mitigation balancing account (10) 156 156 General rate case memorandum accounts (11) 233 376 Vegetation management balancing account (12) 594 592 COVID-19 pandemic protection memorandum accounts (13) 39 84 Other 1,124 942 Total long-term regulatory assets $ 8,914 $ 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 June 30, 2021, $61 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 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 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 June 30, 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 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 June 30, 2021 . Non-current 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. On a go forward basis, the CPPMA applies only to small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. The RUBA applies to residential customers and was approved on April 13, 2021 with an effective date of June 11, 2020. As of June 30, 2021 , the Utility had recorded an aggregate under-collection of $208 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA and the RUBA are in effect. Of the $208 million under-collection, at June 30, 2021, $182 million is recorded in the RUBA current balancing accounts receivable and $26 million is recorded in the CPPMA. The remaining $13 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) June 30, 2021 December 31, 2020 Cost of removal obligations (1) $ 7,139 $ 6,905 Recoveries in excess of AROs (2) 496 458 Public purpose programs (3) 914 948 Employee benefit plans (4) 1,008 995 Tower Licenses (5) 451 — Other 1,210 1,118 Total long-term regulatory liabilities $ 11,218 $ 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 $451 million, $315 million and $136 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) June 30, 2021 December 31, 2020 Electric distribution $ 207 $ — Gas distribution and transmission — 102 Energy procurement 481 413 Public purpose programs 299 292 Fire hazard prevention memorandum account 111 121 Fire risk mitigation memorandum account 30 33 Wildfire mitigation plan memorandum account 148 161 Wildfire mitigation balancing account 40 27 General rate case memorandum accounts 469 313 Vegetation management balancing account 142 115 Insurance premium costs 290 135 Residential uncollectibles balancing accounts 182 — Other 360 289 Total regulatory balancing accounts receivable $ 2,759 $ 2,001 Payable Balance at (in millions) June 30, 2021 December 31, 2020 Electric distribution $ — $ 55 Electric transmission 188 267 Gas distribution and transmission 125 76 Energy procurement 185 158 Public purpose programs 338 410 Other 231 279 Total regulatory balancing accounts payable $ 1,067 $ 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	6 Months Ended
	Jun. 30, 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 June 30, 2021: (in millions) Termination Facility Limit Borrowings Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility June 2026 $ 4,000 (1) $ 670 $ 950 $ 2,380 Utility term loan credit facility (2) January 2022 1,500 1,500 — — Utility receivables securitization program (3) October 2022 1,000 (4) 1,000 — — (4) PG&E Corporation revolving credit facility June 2024 500 — — 500 Total credit facilities $ 7,000 $ 3,170 $ 950 $ 2,880 (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. Revolving Credit Facilities Utility As previously disclosed, on July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”). The Utility Revolving Credit Agreement had a maturity date of July 1, 2023, subject to two one On June 22, 2021, the Utility amended the Utility Revolving Credit Agreement to, among other things, (i) increase the aggregate commitments provided by the lenders thereunder to $4 billion, (ii) extend the maturity date of such agreement to June 22, 2026 and (iii) provide for reduced interest rates and commitment fee rates based on the credit rating of the Utility. PG&E Corporation As previously disclosed, on July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”). The Corporation Revolving Credit Agreement had a maturity date of July 1, 2023, subject to two one On June 22, 2021, PG&E Corporation amended the Corporation Revolving Credit Agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2024 and (ii) modify both the interest rate pricing grid and commitment fee pricing grid. 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 Utility Revolving Credit Agreement and (iii) general corporate purposes. In June 2021, the Utility issued $800 million aggregate principal amount of 3.0% First Mortgage Bonds due June 15, 2028. The proceeds were used for general corporate purposes, including the repayment of borrowings under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement.

EQUITY

EQUITY	6 Months Ended
	Jun. 30, 2021
Equity [Abstract]
EQUITY	EQUITY At the Market Equity Distribution Program On April 30, 2021, PG&E Corporation entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Barclays Capital Inc., BofA Securities, Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as sales agents and as forward sellers (in such capacities as applicable, the “Agents” and the “Forward Sellers”, respectively), and Barclays Bank PLC, Bank of America, N.A., Credit Suisse Capital LLC and Wells Fargo Bank, National Association, as forward purchasers (the “Forward Purchasers”), establishing an at-the-market equity distribution program, pursuant to which PG&E Corporation, through the Agents, may offer and sell from time to time shares of PG&E Corporation’s common stock having an aggregate gross sales price of up to $400 million. PG&E Corporation has no obligation to offer or sell any of its common stock under the Equity Distribution Agreement and may at any time suspend offers under the Equity Distribution Agreement. The Equity Distribution Agreement provides that, in addition to the issuance and sale of shares of common stock by PG&E Corporation to or through the Agents, PG&E Corporation may enter into forward sale agreements (collectively, the “Forward Sale Agreement”) pursuant to which the relevant Forward Purchaser will borrow shares from third parties and, through its affiliated Forward Seller, offer a number of shares of common stock equal to the number of shares of common stock underlying the particular Forward Sale Agreement. During the six months ended June 30, 2021, PG&E Corporation did not sell any shares pursuant to the Equity Distribution Agreement or any Forward Sale Agreement. As of June 30, 2021, there was $400 million available under PG&E Corporation’s at the market equity distribution program for future offerings. 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. Because, as of July 8, 2021, PG&E Corporation and the Utility have agreed to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes (which treatment will be retroactive to the inception of the Fire Victim Trust), any shares owned by the Fire Victim Trust are effectively excluded from the total number of outstanding equity securities when calculating a person’s percentage ownership for purposes of the 4.75% ownership limitation in the Amended Articles. Shares owned by ShareCo are also effectively excluded because it is a disregarded entity for tax purposes. For example, although PG&E Corporation had 2,463,016,638 shares outstanding as of July 26, 2021, only 1,507,529,458 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust and ShareCo) count as outstanding for purposes of the ownership restrictions in the Amended Articles. As such, based on the total number of outstanding equity securities and assuming the Fire Victim Trust has not sold any shares of PG&E Corporation common stock, a person’s effective percentage ownership limitation for purposes of the Amended Articles as of July 26, 2021 was 2.9%. As of July 26, 2021, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock. 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. PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement The tax deduction recorded on shares provided to the Fire Victim Trust under the Plan reflects PG&E Corporation’s conclusion as of June 30, 2021 that it is more likely than not that the Fire Victim Trust would 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 believed 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 transferred to the Fire Victim Trust, could be realized, but only if PG&E Corporation and the Fire Victim Trust could meet certain requirements of the Internal Revenue Code and Treasury Regulations thereunder, relating to sales of PG&E Corporation stock. On April 29, 2021, the Bankruptcy Court entered an order approving the material terms of an agreement (the “PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement”) among PG&E Corporation, the Utility and the Fire Victim Trust that supports the election of the grantor trust treatment. On July 8, 2021, PG&E Corporation, the Utility, PG&E ShareCo LLC, a limited liability company whose sole member is PG&E Corporation (“ShareCo”) and the Fire Victim Trust entered into the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, whereby PG&E Corporation and the Utility agreed to make a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust. With the “grantor trust” election, the Utility’s tax deduction will occur 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 transferred to the Fire Victim Trust. Adjustments in respect of the election to treat the Fire Victim Trust as a “grantor trust” are expected to be reflected in PG&E Corporation’s and the Utility’s quarterly report on Form 10-Q for the quarter ending September 30, 2021. Under the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, the parties agreed to exchange the 477,743,590 shares of PG&E Corporation common stock issued to the Fire Victim Trust pursuant to the Plan (the “Plan Shares”) for an equal number of newly-issued shares of PG&E Corporation common stock (the “New Shares”). The Plan Shares exchanged will be held thereafter by the Utility. Pursuant to the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement, on July 9, 2021, PG&E Corporation issued 477,743,590 New Shares to ShareCo, which has the sole purpose of holding the New Shares in a designated brokerage account to facilitate the exchange process. When the Fire Victim Trust desires to sell any or all of its Plan Shares, the Fire Victim Trust may exchange any number of Plan Shares for a corresponding number of New Shares on a share-for-share basis (without any further consideration payable by either party) and thereafter promptly dispose of the New Shares in one or more transactions with one or more third parties. In the event that the Fire Victim Trust is unable to timely dispose of New Shares under certain circumstances (such shares, the “Nonconforming New Shares”), PG&E Corporation has authorized up to 250,000,000 additional shares of PG&E Corporation common stock, which may be transferred by ShareCo to the Fire Victim Trust on behalf of the Utility, in exchange for the Nonconforming New Shares, following the same procedures as for an exchange of Plan Shares for New Shares. In the event that the Fire Victim Trust disposes of any common stock subject to the PG&E Fire Victim Trust Share Exchange and Tax Matters Agreement without complying with the terms of the agreement, the Fire Victim Trust may be required to make a payment to the Utility designed to compensate the Utility for adverse tax consequences arising from nonconforming sale transactions. 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 June 30, 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	6 Months Ended
	Jun. 30, 2021
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income (loss) attributable to common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income (loss) attributable to common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share amounts) 2021 2020 2021 2020 Income (loss) attributable to common shareholders $ 397 $ (1,972) $ 517 $ (1,601) Weighted average common shares outstanding, basic 1,985 529 1,985 529 Add incremental shares from assumed conversions: Employee share-based compensation 5 — 5 — Equity Units 156 — 156 — Weighted average common shares outstanding, diluted 2,146 529 2,146 529 Total income (loss) per common share, diluted $ 0.18 $ (3.73) $ 0.24 $ (3.03)

DERIVATIVES

DERIVATIVES	6 Months Ended
	Jun. 30, 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 June 30, 2021 December 31, 2020 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 252,270,326 146,642,863 Options 35,515,000 14,140,000 Electricity (MWh) Forwards, Futures and Swaps 10,375,299 9,435,830 Options 411,200 — Congestion Revenue Rights (3) 259,232,639 266,091,470 (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 June 30, 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 $ 100 $ (16) $ 76 $ 160 Noncurrent assets – other 132 — — 132 Current liabilities – other (45) 16 20 (9) Noncurrent liabilities – other (160) — 1 (159) Total commodity risk $ 27 $ — $ 97 $ 124 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 June 30, 2021, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	6 Months Ended
	Jun. 30, 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 June 30, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 294 $ — $ — $ — $ 294 Nuclear decommissioning trusts Short-term investments 10 — — — 10 Global equity securities 2,542 — — — 2,542 Fixed-income securities 1,028 829 — — 1,857 Assets measured at NAV — — — — 28 Total nuclear decommissioning trusts (2) 3,580 829 — — 4,437 Price risk management instruments (Note 8) Electricity — 55 166 16 237 Gas — 11 — 44 55 Total price risk management instruments — 66 166 60 292 Rabbi trusts Fixed-income securities — 104 — — 104 Life insurance contracts — 76 — — 76 Total rabbi trusts — 180 — — 180 Long-term disability trust Short-term investments 6 — — — 6 Assets measured at NAV — — — — 149 Total long-term disability trust 6 — — — 155 TOTAL ASSETS $ 3,880 $ 1,075 $ 166 $ 60 $ 5,358 Liabilities: Price risk management instruments (Note 8) Electricity — 7 184 (24) 167 Gas — 14 — (13) 1 TOTAL LIABILITIES $ — $ 21 $ 184 $ (37) $ 168 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $740 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 and six months ended June 30, 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 on net income resulting from changes in the fair value of these instruments. (See Note 8 above.) Fair Value at (in millions) June 30, 2021 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) / Weighted-Average Price (2) Congestion revenue rights $ 141 $ 81 Market approach CRR auction prices $(320.25) - $320.25 / 0.23 Power purchase agreements $ 25 $ 103 Discounted cash flow Forward prices $(6.25) - $254.65 / 42.38 (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 / 0.30 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 and six months ended June 30, 2021 and 2020: Price Risk Management Instruments (in millions) 2021 2020 Asset (liability) balance as of April 1 $ (94) $ (5) Net realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts (1) 76 (61) Asset (liability) balance as of June 30 $ (18) $ (66) (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. 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) 54 (71) Asset (liability) balance as of June 30 $ (18) $ (66) (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 June 30, 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 June 30, 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 $ 1,883 $ 2,028 $ 1,901 $ 2,175 Utility 32,849 32,891 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 June 30, 2021 Nuclear decommissioning trusts Short-term investments $ 10 $ — $ — $ 10 Global equity securities 508 2,064 (2) 2,570 Fixed-income securities 1,752 114 (9) 1,857 Total (1) $ 2,270 $ 2,178 $ (11) $ 4,437 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 $740 million and $671 million for the periods ended June 30, 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) June 30, 2021 Less than 1 year $ 62 1–5 years 446 5–10 years 493 More than 10 years 856 Total maturities of fixed-income securities $ 1,857 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 401 $ 254 $ 952 $ 787 Gross realized gains on securities 74 8 129 76 Gross realized losses on securities (3) (12) (16) (21)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES	6 Months Ended
	Jun. 30, 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 between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments. 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 EIRs 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 would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire, even though PG&E Corporation did not then have access to the evidence that Cal Fire gathered. On April 20, 2021, the court held an initial hearing in the case. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the criminal complaint. The Sonoma County District Attorney’s Office filed an opposition to the demurrer on June 29, 2021. The Utility’s reply is due on August 19, 2021. The Sonoma County Superior Court is currently scheduled to conduct a hearing on the demurrer on September 9, 2021. 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. As of July 28, 2021, PG&E Corporation and the Utility are aware of 30 complaints on behalf of approximately 607 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. Plaintiffs filed master complaints on July 16, 2021, and PG&E Corporation’s and the Utility’s response is due by August 16, 2021. 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 EIRs, 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 the facts and circumstances available to the Utility as of the filing of the quarterly report on Form 10-Q for the period ended March 31, 2021 (the “Q1 Form 10-Q”), 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 in the first quarter of 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance). The aggregate liability remained unchanged as of June 30, 2021. Between the filing of PG&E Corporation’s and the Utility’s Q1 Form 10-Q and this filing, PG&E Corporation and the Utility entered into settlement agreements to resolve the claims of eight local public entities, including Sonoma County and the City of Santa Rosa, for an aggregate of $31 million, which amount is included in PG&E Corporation’s and the Utility’s $800 million charge. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019. Loss Accrual (in millions) Balance at December 31, 2019 $ — Accrued Losses 625 Balance at December 31, 2020 625 Accrued Losses 175 Payments (1) (31) Balance at June 30, 2021 $ 769 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2019 Kincade fire of approximately $31 million, which has been paid in full by the Utility. 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, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire 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 June 30, 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. 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 EIR 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 relating to the 2020 Zogg fire and are providing information and responses to document requests from the Shasta County District Attorney’s Office relating to the 2020 Zogg fire. 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. If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the 2020 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. As of July 28, 2021, PG&E Corporation and the Utility are aware of 11 complaints on behalf of approximately 297 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. On May 12, 2021, the coordination motion judge ordered that the cases be coordinated, and on June 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. 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 the facts and circumstances available to the Utility as of the filing of the Q1 10-Q, 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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire of $75 million for the three months ended June 30, 2021, for an aggregate liability of $375 million (before available insurance). Between the filing of PG&E Corporation’s and the Utility’s Q1 2021 Form 10-Q and this filing, PG&E Corporation and the Utility entered into settlement agreements to resolve claims for an aggregate amount of $100 million. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2020. Loss Accrual (in millions) Balance at December 31, 2020 $ 275 Accrued Losses 100 Payments (1) (67) Balance at June 30, 2021 $ 308 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2020 Zogg fire of approximately $100 million, of which $67 million has been paid by the Utility. Subsequent to June 30, 2021, the Utility has entered into additional settlements and made additional payments and expects to continue to do so. The aggregate liability of $375 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 $375 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 $375 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, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such 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 June 30, 2021, the Utility has recorded an insurance receivable for $327 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $12 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. 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. 2021 Dixie Fire On July 18, 2021, the Utility submitted an EIR (the “EIR”) reporting that on July 13, 2021, at approximately 4:40 p.m. Pacific Time, a wildfire was observed in Butte County, California (the “2021 Dixie fire”), located in the service territory of the Utility. The Dixie fire has since spread to Plumas County. The Cal Fire Dixie Fire Incident Update dated July 28, 2021 at 4:36 p.m. Pacific Time (the “incident update”), indicated that the 2021 Dixie fire had consumed approximately 218,000 acres at that time. In the incident update, Cal Fire reported no fatalities, no injuries, seven structures damaged and 54 structures destroyed. The EIR indicated that: • On July 13, 2021 at approximately 7:00 a.m., the Utility’s outage system indicated that Cresta Dam off of Highway 70 in the Feather River Canyon lost power; • Due to the challenging terrain and road work resulting in a bridge closure, the responding Utility troubleman was not able to reach the pole with the fuse until approximately 4:40 p.m.; • There the responding Utility troubleman observed two of three fuses blown and what appeared to him to be a healthy green tree leaning into the Bucks Creek 1101 12 kV conductor, which was still intact and suspended on the poles; and • The responding Utility troubleman also observed a fire on the ground near the base of the tree. Since submitting the EIR, the Utility learned that it was notified of the outage by the Rock Creek Switching Center, rather than the outage system. On July 18, 2021, Cal Fire allowed the Utility to observe while Cal Fire took possession of some Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2021 D

OTHER CONTINGENCIES AND COMMITM

OTHER CONTINGENCIES AND COMMITMENTS	6 Months Ended
	Jun. 30, 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 between the Fire Victim Trust and the Utility, and (c) an amount of common stock representing 22.19% of the outstanding shares of PG&E Corporation on the Effective Date, subject to potential adjustments. 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 EIRs 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 would accept Cal Fire’s finding that a Utility transmission line caused the 2019 Kincade fire, even though PG&E Corporation did not then have access to the evidence that Cal Fire gathered. On April 20, 2021, the court held an initial hearing in the case. On May 11, 2021, the Utility filed a demurrer to 25 of the 33 counts contained in the criminal complaint. The Sonoma County District Attorney’s Office filed an opposition to the demurrer on June 29, 2021. The Utility’s reply is due on August 19, 2021. The Sonoma County Superior Court is currently scheduled to conduct a hearing on the demurrer on September 9, 2021. 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. As of July 28, 2021, PG&E Corporation and the Utility are aware of 30 complaints on behalf of approximately 607 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. Plaintiffs filed master complaints on July 16, 2021, and PG&E Corporation’s and the Utility’s response is due by August 16, 2021. 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 EIRs, 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 the facts and circumstances available to the Utility as of the filing of the quarterly report on Form 10-Q for the period ended March 31, 2021 (the “Q1 Form 10-Q”), 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 in the first quarter of 2021 for potential losses in connection with the 2019 Kincade fire of $175 million, for an aggregate liability of $800 million (before available insurance). The aggregate liability remained unchanged as of June 30, 2021. Between the filing of PG&E Corporation’s and the Utility’s Q1 Form 10-Q and this filing, PG&E Corporation and the Utility entered into settlement agreements to resolve the claims of eight local public entities, including Sonoma County and the City of Santa Rosa, for an aggregate of $31 million, which amount is included in PG&E Corporation’s and the Utility’s $800 million charge. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019. Loss Accrual (in millions) Balance at December 31, 2019 $ — Accrued Losses 625 Balance at December 31, 2020 625 Accrued Losses 175 Payments (1) (31) Balance at June 30, 2021 $ 769 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2019 Kincade fire of approximately $31 million, which has been paid in full by the Utility. 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, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such amount, subject to the 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire 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 June 30, 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. 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 EIR 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 relating to the 2020 Zogg fire and are providing information and responses to document requests from the Shasta County District Attorney’s Office relating to the 2020 Zogg fire. 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. If the Utility’s facilities, such as its electric distribution lines, are judicially determined to be the substantial cause of the 2020 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. As of July 28, 2021, PG&E Corporation and the Utility are aware of 11 complaints on behalf of approximately 297 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. On May 12, 2021, the coordination motion judge ordered that the cases be coordinated, and on June 16, 2021, the San Francisco County Superior Court was selected as the site of the coordinated proceeding. 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 the facts and circumstances available to the Utility as of the filing of the Q1 10-Q, 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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the status of negotiations with individual plaintiffs, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2020 Zogg fire of $75 million for the three months ended June 30, 2021, for an aggregate liability of $375 million (before available insurance). Between the filing of PG&E Corporation’s and the Utility’s Q1 2021 Form 10-Q and this filing, PG&E Corporation and the Utility entered into settlement agreements to resolve claims for an aggregate amount of $100 million. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2020. Loss Accrual (in millions) Balance at December 31, 2020 $ 275 Accrued Losses 100 Payments (1) (67) Balance at June 30, 2021 $ 308 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2020 Zogg fire of approximately $100 million, of which $67 million has been paid by the Utility. Subsequent to June 30, 2021, the Utility has entered into additional settlements and made additional payments and expects to continue to do so. The aggregate liability of $375 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 $375 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 $375 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, the Utility may be eligible to make a claim to the Wildfire Fund under AB 1054 to satisfy settled or finally adjudicated eligible claims in excess of such 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 June 30, 2021, the Utility has recorded an insurance receivable for $327 million for probable insurance recoveries in connection with the 2020 Zogg fire, which equals the $375 million probable loss estimate less an initial self-insured retention of $60 million, plus $12 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. 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. 2021 Dixie Fire On July 18, 2021, the Utility submitted an EIR (the “EIR”) reporting that on July 13, 2021, at approximately 4:40 p.m. Pacific Time, a wildfire was observed in Butte County, California (the “2021 Dixie fire”), located in the service territory of the Utility. The Dixie fire has since spread to Plumas County. The Cal Fire Dixie Fire Incident Update dated July 28, 2021 at 4:36 p.m. Pacific Time (the “incident update”), indicated that the 2021 Dixie fire had consumed approximately 218,000 acres at that time. In the incident update, Cal Fire reported no fatalities, no injuries, seven structures damaged and 54 structures destroyed. The EIR indicated that: • On July 13, 2021 at approximately 7:00 a.m., the Utility’s outage system indicated that Cresta Dam off of Highway 70 in the Feather River Canyon lost power; • Due to the challenging terrain and road work resulting in a bridge closure, the responding Utility troubleman was not able to reach the pole with the fuse until approximately 4:40 p.m.; • There the responding Utility troubleman observed two of three fuses blown and what appeared to him to be a healthy green tree leaning into the Bucks Creek 1101 12 kV conductor, which was still intact and suspended on the poles; and • The responding Utility troubleman also observed a fire on the ground near the base of the tree. Since submitting the EIR, the Utility learned that it was notified of the outage by the Rock Creek Switching Center, rather than the outage system. On July 18, 2021, Cal Fire allowed the Utility to observe while Cal Fire took possession of some Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2021 D

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	6 Months Ended
	Jun. 30, 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 June 30, 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 June 30, 2021 or is expected to be provided in the future that was not previously contractually required. As of June 30, 2021 and December 31, 2020, the SPV had net accounts receivable of $2.7 billion and $2.6 billion, respectively, and outstanding borrowings of $1.0 billion 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 June 30, 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 June 30, 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 have been 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 (loss) attributable to 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 and six months ended June 30, 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)	6 Months Ended
	Jun. 30, 2021
Reorganizations [Abstract]
Schedule of Debtor Reorganization Items	Reorganization items, net for the three and six months ended June 30, 2021 and 2020 include the following: Three Months Ended June 30, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 15 1 16 Other (5) — (5) Total reorganization items, net $ 10 $ 1 $ 11 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Three Months Ended June 30, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 1 $ — $ 1 Legal and other (2) 110 1,513 1,623 Interest income — — — Total reorganization items, net $ 111 $ 1,513 $ 1,624 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense, bridge loan facility fees, and trustee fees. Six Months Ended June 30, 2021 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 21 (1) 20 Other (9) — (9) Total reorganization items, net $ 12 $ (1) $ 11 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Six Months Ended June 30, 2020 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 3 $ — $ 3 Legal and other (2) 206 1,598 1,804 Interest income (5) (2) (7) Total reorganization items, net $ 204 $ 1,596 $ 1,800 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) Amount includes $1.5 billion in equity backstop premium expense, bridge loan facility fees, and trustee fees.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 2021 and 2020 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 146 $ 132 $ 16 $ 16 Interest cost 162 179 13 15 Expected return on plan assets (262) (261) (35) (35) Amortization of prior service cost (2) (2) 3 4 Amortization of net actuarial loss 2 1 (8) (5) Net periodic benefit cost 46 49 (11) (5) Regulatory account transfer (2) 37 34 — — Total $ 83 $ 83 $ (11) $ (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. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Service cost for benefits earned (1) $ 293 $ 264 $ 32 $ 31 Interest cost 323 357 26 31 Expected return on plan assets (523) (522) (70) (69) Amortization of prior service cost (3) (3) 7 7 Amortization of net actuarial loss 3 2 (16) (10) Net periodic benefit cost 93 98 (21) (10) Regulatory account transfer (2) 74 68 — — Total $ 167 $ 166 $ (21) $ (10) (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 June 30, 2021 Beginning balance $ (38) $ 17 $ (21) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $1 and $2, respectively) 1 (6) (5) Regulatory account transfer (net of taxes of $0 and $1, respectively) — 4 4 Net current period other comprehensive gain (loss) — — — 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 Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) — (4) (4) Regulatory account transfer (net of taxes of $0 and $0, respectively) 1 1 2 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.) Pension Benefits Other Benefits Total (in millions, net of income tax) Six Months Ended June 30, 2021 Beginning balance $ (39) $ 17 $ (22) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $1 and $4, respectively) 2 (12) (10) Regulatory account transfer (net of taxes of $0 and $2, respectively) 1 7 8 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 Benefits Total (in millions, net of income tax) Six Months Ended June 30, 2020 Beginning balance $ (22) $ 17 $ (5) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $1 and $3, respectively) 1 (7) (6) Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 2 3 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 June 30, Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Electric Revenue from contracts with customers Residential $ 1,352 $ 987 $ 2,815 $ 2,230 Commercial 1,183 1,075 2,196 2,082 Industrial 305 342 632 682 Agricultural 431 368 583 491 Public street and highway lighting 18 17 35 34 Other (1) 285 269 222 203 Total revenue from contracts with customers - electric 3,574 3,058 6,483 5,722 Regulatory balancing accounts (2) 377 377 863 753 Total electric operating revenue $ 3,951 $ 3,435 $ 7,346 $ 6,475 Natural gas Revenue from contracts with customers Residential $ 418 $ 426 $ 1,626 $ 1,492 Commercial 139 110 384 344 Transportation service only 346 296 672 643 Other (1) (137) (159) (184) (180) Total revenue from contracts with customers - gas 766 673 2,498 2,299 Regulatory balancing accounts (2) 498 425 87 65 Total natural gas operating revenue 1,264 1,098 2,585 2,364 Total operating revenues $ 5,215 $ 4,533 $ 9,931 $ 8,839 (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)	6 Months Ended
	Jun. 30, 2021
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Balance at (in millions) June 30, 2021 December 31, 2020 Pension benefits (1) $ 2,172 $ 2,245 Environmental compliance costs 1,046 1,112 Utility retained generation (2) 156 181 Price risk management 160 204 Unamortized loss, net of gain, on reacquired debt 43 49 Catastrophic event memorandum account (3) 916 842 Wildfire expense memorandum account (4) 230 400 Fire hazard prevention memorandum account (5) 87 137 Fire risk mitigation memorandum account (6) 52 66 Wildfire mitigation plan memorandum account (7) 407 390 Deferred income taxes (8) 1,257 908 Insurance premium costs (9) 242 294 Wildfire mitigation balancing account (10) 156 156 General rate case memorandum accounts (11) 233 376 Vegetation management balancing account (12) 594 592 COVID-19 pandemic protection memorandum accounts (13) 39 84 Other 1,124 942 Total long-term regulatory assets $ 8,914 $ 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 June 30, 2021, $61 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 and other incremental costs associated with fire risk mitigation. Recovery of FRMMA costs is subject to CPUC review and approval. (7) Includes costs associated with the 2019 WMP for the period June 5, 2019 through December 31, 2019 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 June 30, 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 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 June 30, 2021 . Non-current 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. On a go forward basis, the CPPMA applies only to small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. The RUBA applies to residential customers and was approved on April 13, 2021 with an effective date of June 11, 2020. As of June 30, 2021 , the Utility had recorded an aggregate under-collection of $208 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA and the RUBA are in effect. Of the $208 million under-collection, at June 30, 2021, $182 million is recorded in the RUBA current balancing accounts receivable and $26 million is recorded in the CPPMA. The remaining $13 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) June 30, 2021 December 31, 2020 Cost of removal obligations (1) $ 7,139 $ 6,905 Recoveries in excess of AROs (2) 496 458 Public purpose programs (3) 914 948 Employee benefit plans (4) 1,008 995 Tower Licenses (5) 451 — Other 1,210 1,118 Total long-term regulatory liabilities $ 11,218 $ 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) June 30, 2021 December 31, 2020 Electric distribution $ 207 $ — Gas distribution and transmission — 102 Energy procurement 481 413 Public purpose programs 299 292 Fire hazard prevention memorandum account 111 121 Fire risk mitigation memorandum account 30 33 Wildfire mitigation plan memorandum account 148 161 Wildfire mitigation balancing account 40 27 General rate case memorandum accounts 469 313 Vegetation management balancing account 142 115 Insurance premium costs 290 135 Residential uncollectibles balancing accounts 182 — Other 360 289 Total regulatory balancing accounts receivable $ 2,759 $ 2,001
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) June 30, 2021 December 31, 2020 Electric distribution $ — $ 55 Electric transmission 188 267 Gas distribution and transmission 125 76 Energy procurement 185 158 Public purpose programs 338 410 Other 231 279 Total regulatory balancing accounts payable $ 1,067 $ 1,245

DEBT (Tables)

DEBT (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2021: (in millions) Termination Facility Limit Borrowings Outstanding Letters of Credit Outstanding Facility Utility revolving credit facility June 2026 $ 4,000 (1) $ 670 $ 950 $ 2,380 Utility term loan credit facility (2) January 2022 1,500 1,500 — — Utility receivables securitization program (3) October 2022 1,000 (4) 1,000 — — (4) PG&E Corporation revolving credit facility June 2024 500 — — 500 Total credit facilities $ 7,000 $ 3,170 $ 950 $ 2,880 (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.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	6 Months Ended
	Jun. 30, 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 (loss) attributable to common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share amounts) 2021 2020 2021 2020 Income (loss) attributable to common shareholders $ 397 $ (1,972) $ 517 $ (1,601) Weighted average common shares outstanding, basic 1,985 529 1,985 529 Add incremental shares from assumed conversions: Employee share-based compensation 5 — 5 — Equity Units 156 — 156 — Weighted average common shares outstanding, diluted 2,146 529 2,146 529 Total income (loss) per common share, diluted $ 0.18 $ (3.73) $ 0.24 $ (3.03)

DERIVATIVES (Tables)

DERIVATIVES (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2021 December 31, 2020 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 252,270,326 146,642,863 Options 35,515,000 14,140,000 Electricity (MWh) Forwards, Futures and Swaps 10,375,299 9,435,830 Options 411,200 — Congestion Revenue Rights (3) 259,232,639 266,091,470 (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 June 30, 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 $ 100 $ (16) $ 76 $ 160 Noncurrent assets – other 132 — — 132 Current liabilities – other (45) 16 20 (9) Noncurrent liabilities – other (160) — 1 (159) Total commodity risk $ 27 $ — $ 97 $ 124 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 June 30, 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 $ 100 $ (16) $ 76 $ 160 Noncurrent assets – other 132 — — 132 Current liabilities – other (45) 16 20 (9) Noncurrent liabilities – other (160) — 1 (159) Total commodity risk $ 27 $ — $ 97 $ 124 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)	6 Months Ended
	Jun. 30, 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 June 30, 2021 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 294 $ — $ — $ — $ 294 Nuclear decommissioning trusts Short-term investments 10 — — — 10 Global equity securities 2,542 — — — 2,542 Fixed-income securities 1,028 829 — — 1,857 Assets measured at NAV — — — — 28 Total nuclear decommissioning trusts (2) 3,580 829 — — 4,437 Price risk management instruments (Note 8) Electricity — 55 166 16 237 Gas — 11 — 44 55 Total price risk management instruments — 66 166 60 292 Rabbi trusts Fixed-income securities — 104 — — 104 Life insurance contracts — 76 — — 76 Total rabbi trusts — 180 — — 180 Long-term disability trust Short-term investments 6 — — — 6 Assets measured at NAV — — — — 149 Total long-term disability trust 6 — — — 155 TOTAL ASSETS $ 3,880 $ 1,075 $ 166 $ 60 $ 5,358 Liabilities: Price risk management instruments (Note 8) Electricity — 7 184 (24) 167 Gas — 14 — (13) 1 TOTAL LIABILITIES $ — $ 21 $ 184 $ (37) $ 168 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $740 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) June 30, 2021 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) / Weighted-Average Price (2) Congestion revenue rights $ 141 $ 81 Market approach CRR auction prices $(320.25) - $320.25 / 0.23 Power purchase agreements $ 25 $ 103 Discounted cash flow Forward prices $(6.25) - $254.65 / 42.38 (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 / 0.30 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 and six months ended June 30, 2021 and 2020: Price Risk Management Instruments (in millions) 2021 2020 Asset (liability) balance as of April 1 $ (94) $ (5) Net realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts (1) 76 (61) Asset (liability) balance as of June 30 $ (18) $ (66) (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. 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) 54 (71) Asset (liability) balance as of June 30 $ (18) $ (66) (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 June 30, 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 $ 1,883 $ 2,028 $ 1,901 $ 2,175 Utility 32,849 32,891 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 June 30, 2021 Nuclear decommissioning trusts Short-term investments $ 10 $ — $ — $ 10 Global equity securities 508 2,064 (2) 2,570 Fixed-income securities 1,752 114 (9) 1,857 Total (1) $ 2,270 $ 2,178 $ (11) $ 4,437 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 $740 million and $671 million for the periods ended June 30, 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) June 30, 2021 Less than 1 year $ 62 1–5 years 446 5–10 years 493 More than 10 years 856 Total maturities of fixed-income securities $ 1,857
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 June 30, Six Months Ended June 30, (in millions) 2021 2020 2021 2020 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 401 $ 254 $ 952 $ 787 Gross realized gains on securities 74 8 129 76 Gross realized losses on securities (3) (12) (16) (21)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 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 108 — — 108 Reimbursements — — — — Balance at June 30, 2021 $ 327 $ 430 $ 25 $ 782
Schedule of Loss Contingencies by Contingency	The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2019 Kincade fire since December 31, 2019. Loss Accrual (in millions) Balance at December 31, 2019 $ — Accrued Losses 625 Balance at December 31, 2020 625 Accrued Losses 175 Payments (1) (31) Balance at June 30, 2021 $ 769 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2019 Kincade fire of approximately $31 million, which has been paid in full by the Utility. The following table presents changes in the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses for claims arising from the 2020 Zogg fire since December 31, 2020. Loss Accrual (in millions) Balance at December 31, 2020 $ 275 Accrued Losses 100 Payments (1) (67) Balance at June 30, 2021 $ 308 (1) As of June 30, 2021, the Utility entered into settlement agreements in connection with the 2020 Zogg fire of approximately $100 million, of which $67 million has been paid by the Utility. Subsequent to June 30, 2021, the Utility has entered into additional settlements and made additional payments and expects to continue to do so.

OTHER CONTINGENCIES AND COMMI_2

OTHER CONTINGENCIES AND COMMITMENTS (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 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) June 30, 2021 December 31, 2020 Topock natural gas compressor station $ 295 $ 303 Hinkley natural gas compressor station 129 132 Former manufactured gas plant sites owned by the Utility or third parties (1) 681 659 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 112 111 Fossil fuel-fired generation facilities and sites (3) 75 96 Total environmental remediation liability $ 1,292 $ 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)	6 Months Ended
	Jun. 30, 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) claim in Thousands, $ in Millions	Oct. 27, 2020	Jun. 30, 2021USD ($)claim	Dec. 31, 2020USD ($)
Debt Instrument [Line Items]
Proofs of claims		100
Disputed claims and customer refunds | $		$ 245	$ 242
Deadline extension period	180 days
Subrogation Wildfire Trust and Fire Victim Trust
Debt Instrument [Line Items]
Proofs of claims		80

BANKRUPTCY FILING (Reorganizati

BANKRUPTCY FILING (Reorganization Items, Net) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Pacific Gas & Electric Co (Utility)
Debt Instrument [Line Items]
Payments (refunds) for reorganization items	$ 24	$ 90	$ 41	$ 207
PG&E Corporation
Debt Instrument [Line Items]
Payments (refunds) for reorganization items	$ 2	$ 33	$ 31	$ 90

BANKRUPTCY FILING (Schedule of

BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Reorganizations [Line Items]
Debtor-in-possession financing costs	$ 0	$ 1	$ 0	$ 3
Legal and other	16	1,623	20	1,804
Other	(5)
Interest income		0	(9)	(7)
Total reorganization items, net	11	1,624	11	1,800
Equity backstop premium expense, bridge loan facility fees, and trustee fees	1,500		1,500
PG&E Corporation
Reorganizations [Line Items]
Debtor-in-possession financing costs	0	0	0	0
Legal and other	1	1,513	(1)	1,598
Other	0
Interest income		0	0	(2)
Total reorganization items, net	1	1,513	(1)	1,596
Utility
Reorganizations [Line Items]
Debtor-in-possession financing costs	0	1	0	3
Legal and other	15	110	21	206
Other	(5)
Interest income		0	(9)	(5)
Total reorganization items, net	$ 10	$ 111	$ 12	$ 204

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Variable Interest Entities) (Details) - USD ($)	Jun. 30, 2021	Dec. 31, 2020
Debt [Line Items]
Long-term debt, gross	$ 3,170,000,000
Receivables Securitization Program | PG&E AR Facility, LLC
Debt [Line Items]
Accounts Receivable from Securitization	2,700,000,000	$ 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	$ 1,000,000,000	$ 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 146	$ 132	$ 293	$ 264
Interest cost	162	179	323	357
Expected return on plan assets	(262)	(261)	(523)	(522)
Amortization of prior service cost	(2)	(2)	(3)	(3)
Amortization of net actuarial loss	2	1	3	2
Net periodic benefit cost	46	49	93	98
Regulatory account transfer	37	34	74	68
Total	83	83	167	166
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	16	16	32	31
Interest cost	13	15	26	31
Expected return on plan assets	(35)	(35)	(70)	(69)
Amortization of prior service cost	3	4	7	7
Amortization of net actuarial loss	(8)	(5)	(16)	(10)
Net periodic benefit cost	(11)	(5)	(21)	(10)
Regulatory account transfer	0	0	0	0
Total	$ (11)	$ (5)	$ (21)	$ (10)

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	$ 21,379	$ 5,759	$ 21,253	$ 5,388
Net current period other comprehensive gain (loss)	0	0	1	0
Ending balance	21,799	3,801	21,799	3,801
Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	0	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	0	0
Accumulated Other Comprehensive Income (Loss)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(21)	(5)	(22)	(5)
Ending balance	(21)	(5)	(21)	(5)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning balance	(38)	(22)	(39)	(22)
Ending balance	(38)	(22)	(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	17	17
Ending balance	17	17	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	1	2	3	3
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)	(2)	(2)
Amount attributable to tax	1	1	1	1
Amortization of prior service cost | Other Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	3	5	5
Amount attributable to tax	1	1	2	2
Amortization of net actuarial loss
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(5)	(4)	(10)	(6)
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	0	2	1
Amount attributable to tax	1	1	1	1
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)	(4)	(12)	(7)
Amount attributable to tax	2	1	4	3
Regulatory account transfer
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	4	2	8	3
Regulatory account transfer | Pension Benefits
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	1	1	1
Amount attributable to tax	0	0	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	4	1	7	2
Amount attributable to tax	$ 1	$ 0	$ 2	$ 1

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Accounting Policies [Abstract]
Period for probable revenue recovery			24 months
Pacific Gas & Electric Co (Utility)
Revenue from contracts with customers
Total operating revenues	$ 5,215	$ 4,533	$ 9,931	$ 8,839
Pacific Gas & Electric Co (Utility) | Electric
Revenue from contracts with customers
Total revenue from contracts with customers	3,574	3,058	6,483	5,722
Regulatory balancing accounts	377	377	863	753
Total operating revenues	3,951	3,435	7,346	6,475
Pacific Gas & Electric Co (Utility) | Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,352	987	2,815	2,230
Pacific Gas & Electric Co (Utility) | Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,183	1,075	2,196	2,082
Pacific Gas & Electric Co (Utility) | Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	305	342	632	682
Pacific Gas & Electric Co (Utility) | Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	431	368	583	491
Pacific Gas & Electric Co (Utility) | Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	18	17	35	34
Pacific Gas & Electric Co (Utility) | Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	285	269	222	203
Pacific Gas & Electric Co (Utility) | Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	766	673	2,498	2,299
Regulatory balancing accounts	498	425	87	65
Total operating revenues	1,264	1,098	2,585	2,364
Pacific Gas & Electric Co (Utility) | Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	418	426	1,626	1,492
Pacific Gas & Electric Co (Utility) | Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	139	110	384	344
Pacific Gas & Electric Co (Utility) | Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	346	296	672	643
Pacific Gas & Electric Co (Utility) | Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ (137)	$ (159)	$ (184)	$ (180)

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Wildfire Fund) (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021USD ($)contribution	Jun. 30, 2020USD ($)	Jun. 30, 2021USD ($)contribution	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)	Jul. 12, 2019USD ($)
Loss Contingencies [Line Items]
Expected capitalization, proceeds of bond	$ 10,500		$ 10,500			$ 10,500
Expected capitalization, initial contribution	7,500		7,500			7,500
Expected capitalization, annual contribution	$ 300		$ 300			$ 300
Expected wildfire fund allocation metric, percentage	64.20%		64.20%
Expected wildfire fund allocation metric, initial contribution	$ 4,800		$ 4,800
Expected wildfire fund allocation metric, annual contributions	193		193
Initial contribution payment	4,800		4,800
Annual contribution, first payment	193		193
Annual contribution, second payment	$ 193		$ 193
Number of remaining annual contributions | contribution	8		8
Wildfire fund, current asset	$ 464		$ 464		$ 464
Wildfire fund, noncurrent asset	5,584		5,584		5,816
Wildfire Fund expense	$ 118	$ 173	$ 237	$ 173
Monte carlo simulation, historical data, period			12 years
Amortization period			6 years
Percentage assumption change	10.00%		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		464
Wildfire fund, noncurrent asset	5,584		5,584		$ 5,816
Wildfire Fund expense	118	$ 173	$ 237	$ 173
5 year period
Loss Contingencies [Line Items]
Historical data period			5 years
Average annual statewide claims or settlements	6,500		$ 6,500
12 year period
Loss Contingencies [Line Items]
Historical data period			12 years
Average annual statewide claims or settlements	2,900		$ 2,900
Wildfire Fund asset
Loss Contingencies [Line Items]
Finite-lived intangible asset, useful life			15 years
Current liabilities - other
Loss Contingencies [Line Items]
Litigation liability, current	193		$ 193
Noncurrent liabilities – other
Loss Contingencies [Line Items]
Wildfire fund, noncurrent	$ 1,300		$ 1,300

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Credit Losses) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit loss	$ 113	$ 44	$ 189	$ 44
Total regulatory balancing accounts receivable
Financing Receivable, Allowance for Credit Loss [Line Items]
Total regulatory balancing accounts, net	2,759		2,759		$ 2,001
Total regulatory balancing accounts receivable | Residential uncollectibles balancing accounts
Financing Receivable, Allowance for Credit Loss [Line Items]
Total regulatory balancing accounts, net	182		182		$ 0
COVID-19 pandemic protection memorandum account
Financing Receivable, Allowance for Credit Loss [Line Items]
Regulatory assets	26		26
Federal Energy Regulatory Commission (FERC)
Financing Receivable, Allowance for Credit Loss [Line Items]
Regulatory assets	$ 26		$ 26

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	6 Months Ended	18 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 8,914	$ 8,914	$ 8,978
Retained generation asset costs	1,200	1,200
Regulatory assets	622	622	410
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,172	2,172	2,245
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,046	1,046	1,112
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	156	156	181
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	160	160	204
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	43	43	49
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	916	916	842
Catastrophic event memorandum account | COVID-19
Regulatory Assets [Line Items]
Total long-term regulatory assets	61	61
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	230	230	400
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	87	87	137
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	52	52	66
Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	407	407	390
Deferred income taxes
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,257	1,257	908
Insurance premium costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	242	242	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	$ 233	$ 233	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	$ 39	39	84
Regulatory assets	26	26
COVID-19 pandemic protection memorandum account, undercollection bad debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	208	208
COVID-19 pandemic protection memorandum account, program and accounts receivable financing costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	13	13
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	2,759	2,759	2,001
Total regulatory balancing accounts receivable | Residential uncollectibles balancing accounts
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	182	182	0
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 1,124	$ 1,124	$ 942

REGULATORY ASSETS, LIABILITIE_4

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 11,218	$ 10,424
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	451
Federal Energy Regulatory Commission (FERC)
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	315
California Public Utilities Commission (CPUC)
Regulatory Liabilities [Line Items]
Proceeds received from sale of transmission tower wireless licenses, refunded to customers	136
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	7,139	6,905
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	496	458
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	914	948
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	1,008	995
Tower Licenses
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	451	0
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,210	$ 1,118

REGULATORY ASSETS, LIABILITIE_5

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,067	$ 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	188	267
Total regulatory balancing accounts payable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	125	76
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	185	158
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	338	410
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	231	279
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	2,759	2,001
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	207	0
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	102
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	481	413
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	299	292
Total regulatory balancing accounts receivable | Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	111	121
Total regulatory balancing accounts receivable | Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	30	33
Total regulatory balancing accounts receivable | Wildfire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	148	161
Total regulatory balancing accounts receivable | Wildfire mitigation balancing account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	40	27
Total regulatory balancing accounts receivable | General rate case memorandum accounts
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	469	313
Total regulatory balancing accounts receivable | Vegetation management balancing account
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	142	115
Total regulatory balancing accounts receivable | Insurance premium costs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	290	135
Total regulatory balancing accounts receivable | Residential uncollectibles balancing accounts
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	182	0
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 360	$ 289

DEBT (Credit Facility) (Details

DEBT (Credit Facility) (Details) - USD ($)	Mar. 11, 2021	Jun. 30, 2021	Dec. 31, 2020	Jul. 01, 2020
Debt [Line Items]
Aggregate Limit		$ 7,000,000,000
Borrowings Outstanding		3,170,000,000
Letters of Credit Outstanding		950,000,000
Facility Availability		2,880,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Aggregate Limit		500,000,000		$ 500,000,000
Borrowings Outstanding		0
Letters of Credit Outstanding		0
Facility Availability		500,000,000
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Aggregate Limit		4,000,000,000		$ 3,500,000,000
Borrowings Outstanding		670,000,000
Letters of Credit Outstanding		950,000,000
Facility Availability		2,380,000,000
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		1,000,000,000	$ 1,000,000,000
Letters of Credit Outstanding		0
Facility Availability		$ 0

DEBT (Narrative) (Details)

DEBT (Narrative) (Details)	Jul. 01, 2020USD ($)numberOfExtensionOptionnumberOfClaimHolder	Mar. 31, 2021USD ($)	Jul. 22, 2021USD ($)	Jun. 30, 2021USD ($)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity				$ 7,000,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000			500,000,000
Debt, number of extension options | numberOfExtensionOption	2
Debt instrument, extension option, term	1 year
Revolving Credit Facility | Pacific Gas & Electric Co (Utility)
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$ 3,500,000,000			4,000,000,000
Debt, number of extension options | numberOfClaimHolder	2
Debt instrument, extension option, term	1 year
Revolving Credit Facility | Pacific Gas & Electric Co (Utility) | Subsequent event
Debt [Line Items]
Line of credit facility, maximum borrowing capacity			$ 4,000,000,000
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
First Mortgage Bonds, Exchange Stated Maturity 2028
Debt [Line Items]
Debt instrument, face amount				$ 800,000,000
Stated interest rate				3.00%

EQUITY (Narrative) (Details)

EQUITY (Narrative) (Details) - USD ($)	Jul. 09, 2021	Jul. 26, 2021	Jul. 08, 2021	Jun. 30, 2021	Apr. 30, 2021	Dec. 31, 2020
Schedule Of Changes In Equity [Line Items]
Common stock, shares outstanding (in shares)				1,985,273,048		1,984,678,673
PG&E Corporation | Subsequent event
Schedule Of Changes In Equity [Line Items]
Common stock, shares outstanding (in shares)		2,463,016,638
Common stock, shares outstanding, adjusted (in shares)		1,507,529,458
PG&E Corporation | Common Stock | Fire Victim Trust Share Exchange and Tax Matters Agreement
Schedule Of Changes In Equity [Line Items]
Transfer of shares to Fire Victim Trust (in shares)				477,743,590
PG&E Corporation | Common Stock | Fire Victim Trust Share Exchange and Tax Matters Agreement | Subsequent event
Schedule Of Changes In Equity [Line Items]
Stock issued during period, shares, new issues (in shares)	477,743,590
PG&E Corporation | Common Stock | At The Market Equity Distribution Program
Schedule Of Changes In Equity [Line Items]
Sale of stock, number of shares issued in transaction, amount				$ 400,000,000	$ 400,000,000
PG&E Corporation | Minimum
Schedule Of Changes In Equity [Line Items]
Percentage of equity security ownership with board of director approval				4.75%
PG&E Corporation | Minimum | Subsequent event
Schedule Of Changes In Equity [Line Items]
Percentage of equity security ownership with board of director approval		2.90%	4.75%
PG&E Corporation | Maximum | Fire Victim Trust Share Exchange and Tax Matters Agreement | Subsequent event
Schedule Of Changes In Equity [Line Items]
Common stock, shares authorized, reserve, additional shares due to nonconforming new shares (in shares)	250,000,000

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Earnings Per Share [Abstract]
Income (loss) attributable to common shareholders	$ 397	$ (1,972)	$ 517	$ (1,601)
Income (loss) attributable to common shareholders	$ 397	$ (1,972)	$ 517	$ (1,601)
Weighted average common shares outstanding, basic (in shares)	1,985	529	1,985	529
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	5	0	5	0
Equity Units (in shares)	156	0	156	0
Weighted average common shares outstanding, diluted (in shares)	2,146	529	2,146	529
Total income (loss) per common share, diluted (in dollars per share)	$ 0.18	$ (3.73)	$ 0.24	$ (3.03)

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Jun. 30, 2021MWhMMBTU	Dec. 31, 2020MMBTUMWh
Forwards, Futures and Swaps | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	252,270,326	146,642,863
Forwards, Futures and Swaps | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	10,375,299	9,435,830
Options | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	35,515,000	14,140,000
Options | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	411,200	0
Congestion Revenue Rights | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	259,232,639	266,091,470

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ 27	$ (73)
Derivative Asset, Netting	0	0
Cash Collateral	97	140
Total Derivative Balance, Assets	124	67
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	100	33
Derivative Asset, Netting	(16)	0
Cash Collateral	76	115
Total Derivative Balance, Assets	160	148
Noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	132	136
Derivative Asset, Netting	0	0
Cash Collateral	0	0
Total Derivative Balance, Assets	132	136
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(45)	(38)
Derivative Liability, Netting	16	0
Cash Collateral	20	15
Total Derivative Balance, Liabilities	(9)	(23)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(160)	(204)
Derivative Liability, Netting	0	0
Cash Collateral	1	10
Total Derivative Balance, Liabilities	$ (159)	$ (194)

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Assets:
Short-term investments	$ 294	$ 470
Price risk management instruments, netting	60	115
Price risk management instruments, assets	292	284
TOTAL ASSETS	5,358	5,315
Liabilities:
Price risk management instruments, netting	(37)	(25)
TOTAL LIABILITIES	168	217
Amount primarily related to deferred taxes on appreciation of investment value	740	671
Nuclear decommissioning trusts
Assets:
Short-term investments	10	27
Global equity securities	2,542	2,398
Fixed-income securities	1,857	1,759
TOTAL ASSETS	4,437	4,209
Rabbi trusts
Assets:
Fixed-income securities	104	106
Life insurance contracts	76	79
TOTAL ASSETS	180	185
Long-term disability trust
Assets:
Short-term investments	6	9
TOTAL ASSETS	155	167
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	16	2
Price risk management instruments, assets	237	170
Liabilities:
Price risk management instruments, netting	(24)	(25)
Price risk management instruments, liabilities	167	214
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	44	113
Price risk management instruments, assets	55	114
Liabilities:
Price risk management instruments, netting	(13)	0
Price risk management instruments, liabilities	1	3
Level 1
Assets:
Short-term investments	294	470
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	3,880	3,828
Liabilities:
TOTAL LIABILITIES	0	0
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	10	27
Global equity securities	2,542	2,398
Fixed-income securities	1,028	924
TOTAL ASSETS	3,580	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	6	9
TOTAL ASSETS	6	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	66	3
TOTAL ASSETS	1,075	1,023
Liabilities:
TOTAL LIABILITIES	21	4
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	829	835
TOTAL ASSETS	829	835
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	104	106
Life insurance contracts	76	79
TOTAL ASSETS	180	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	55	2
Liabilities:
Price risk management instruments, gross subject to netting	7	1
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	11	1
Liabilities:
Price risk management instruments, gross subject to netting	14	3
Level 3
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	166	166
TOTAL ASSETS	166	166
Liabilities:
TOTAL LIABILITIES	184	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	166	166
Liabilities:
Price risk management instruments, gross subject to netting	184	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	28	25
Assets measured at NAV | Long-term disability trust
Assets:
Assets measured at NAV	$ 149	$ 158

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2021USD ($)$ / MWh	Dec. 31, 2020USD ($)$ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 5,358	$ 5,315
Liabilities | $	168	217
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	141	153
Liabilities | $	$ 81	$ 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	0.23	0.30
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 25	$ 13
Liabilities | $	$ 103	$ 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	(6.25)	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	254.65	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	42.38	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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset (liability) balance	$ (94)	$ (5)	$ (72)	$ 5
Net Realized and Unrealized Gains (Losses) [Abstract]
Included in regulatory assets and liabilities or balancing accounts	76	(61)	54	(71)
Ending asset (liability) balance	$ (18)	$ (66)	$ (18)	$ (66)

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 1,883	$ 1,901
Carrying Amount | Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	32,849	29,664
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	2,028	2,175
Fair Value | Utility | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 32,891	$ 32,632

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 2,270	$ 2,180
Total Unrealized Gains	2,178	2,033
Total Unrealized Losses	(11)	(4)
Total Fair Value	4,437	4,209
Amount primarily related to deferred taxes on appreciation of investment value	740	671
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	10	27
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	10	27
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	508	543
Total Unrealized Gains	2,064	1,881
Total Unrealized Losses	(2)	(1)
Total Fair Value	2,570	2,423
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,752	1,610
Total Unrealized Gains	114	152
Total Unrealized Losses	(9)	(3)
Total Fair Value	$ 1,857	$ 1,759

FAIR VALUE MEASUREMENTS (Sche_2

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Debt Securities, Available-for-sale [Line Items]
Total fair value	$ 4,437	$ 4,209
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	62
1–5 years	446
5–10 years	493
More than 10 years	856
Total fair value	$ 1,857	$ 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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 401	$ 254	$ 952	$ 787
Gross realized gains on securities	74	8	129	76
Gross realized losses on securities	$ (3)	$ (12)	$ (16)	$ (21)

WILDFIRE- RELATED CONTINGENCIES

WILDFIRE- RELATED CONTINGENCIES (Restructuring Support Agreement) (Details) - USD ($) $ in Millions	Jun. 12, 2020	Dec. 06, 2019
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
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, 2020 Zogg Fire and 2021 Dixie Fire) (Details) $ in Millions	Nov. 04, 2019numberOfPeople	Jun. 30, 2021USD ($)localPublicEntity	Mar. 31, 2021USD ($)	Jun. 30, 2021USD ($)	Dec. 31, 2020USD ($)	Jul. 28, 2021complaintcivil_caseplaintiffnumberOfPlaintiff	Jul. 25, 2021a	Jul. 18, 2021astructurefuseinjuryfatality	May 11, 2021count	Apr. 06, 2021felonymisdemeanorminorfirefighter_structure	Sep. 27, 2020astructurefatalityinjury	Oct. 23, 2019astructurenumberOfFatalitycustomerinjury
Loss Contingencies [Line Items]
Insurance settlements receivable | $		$ 782		$ 782	$ 674
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	$ 800	800	625
Potential loss contingency, additional | $			175
Number of settlement agreements entered into with local public entities (local public entity) | localPublicEntity		8
Settlement amount | $		$ 31		31
Insurance settlements receivable | $		430		430	430
2019 Kincade Fire | Subsequent event
Loss Contingencies [Line Items]
Number of complaint (complaint) | complaint						30
Number of plaintiffs represented by complaints (plaintiff) | plaintiff						607
2019 Kincade Fire | Pacific Gas & Electric Co (Utility)
Loss Contingencies [Line Items]
Number of demurrer filed (count) | count									25
Number of criminal complaints (count) | count									33
2019 Kincade Fire | 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 | $		375		375	275
Potential loss contingency, additional | $		75	$ 25
Settlement amount | $		100
Insurance settlements receivable | $		327		327	219
Number of single family homes destroyed (structure) | structure											63
Liability insurance coverage | $		611		611
Initial self-insured retention per occurrence | $		$ 60		60
Legal fees | $				$ 12
2020 Zogg Fire | Subsequent event
Loss Contingencies [Line Items]
Number of complaint (complaint) | complaint						11
Number of plaintiffs represented by complaints (plaintiff) | numberOfPlaintiff						297
Number of civil cases (civil case) | civil_case						5
2020 Zogg Fire | Maximum
Loss Contingencies [Line Items]
Liability insurance coverage | $					$ 867.5
2021 Dixie Fire | Subsequent event
Loss Contingencies [Line Items]
Number of acres burned (acre) | a								2,180
Number of fatalities (fatality) | fatality								0
Number of injuries (injuries) | injury								0
Number of structures destroyed (structure) | structure								54
Number of structures damaged (structure) | structure								7
Number of fuses (fuse) | fuse								3
Number of fuses blown (fuse) | fuse								2
2021 Fly Fire | Subsequent event
Loss Contingencies [Line Items]
Number of acres burned (acre) | a							4,300
Percentage of fire contained							5.00%

WILDFIRE-RELATED CONTINGENCIE_3

WILDFIRE-RELATED CONTINGENCIES (Losses For Claims) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020
2019 Kincade Fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance		$ 625	$ 0
Accrued Losses		175	625
Payments		(31)
Loss accrual, ending balance	$ 769	769	625
Settlement reached	31	31
Litigation payment		31
2020 Zogg Fire
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance		275
Accrued Losses		100
Payments		(67)
Loss accrual, ending balance	308	308	$ 275
Settlement reached	$ 100
2020 Zogg Fire | Pacific Gas & Electric Co (Utility)
Loss Contingency Accrual [Roll Forward]
Litigation payment		$ 67

WILDFIRE-RELATED CONTINGENCIE_4

WILDFIRE-RELATED CONTINGENCIES (Insurance) (Details) - USD ($) $ in Millions	Apr. 29, 2021	Jun. 30, 2021	Jun. 30, 2021	Aug. 31, 2020
Loss Contingencies [Line Items]
Prepaid Insurance		$ 301	$ 301
Insurance premium costs, recovery, coverage amount		1,400	1,400
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Initial self-insured retention per occurrence		60	60
Insurance Coverage for Wildfire Events | April 13, 2021 to April 1, 2022
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 Wildfire Events | June 1, 2021 to April 1, 2022
Loss Contingencies [Line Items]
Costs for insurance coverage		89
Insurance Coverage For Non-Wildfire Events
Loss Contingencies [Line Items]
Initial self-insured retention per occurrence		10	10
Insurance Coverage For Non-Wildfire Events | April 13, 2021 to April 1, 2022
Loss Contingencies [Line Items]
Liability insurance coverage		50	50
Insurance Coverage For Non-Wildfire Events | August 1, 2020 to August 1, 2021
Loss Contingencies [Line Items]
Liability insurance coverage		140	140
Insurance Coverage For Non-Wildfire Events | June 1, 2021 to April 1, 2022
Loss Contingencies [Line Items]
Liability insurance coverage		535	$ 535
Insurance Coverage For Non-Wildfire Events | Extension to April 1, 2022
Loss Contingencies [Line Items]
Costs for insurance coverage		$ 30

WILDFIRE-RELATED CONTINGENCIE_5

WILDFIRE-RELATED CONTINGENCIES (Insurance Receivable) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2021USD ($)
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	$ 674
Accrued insurance recoveries	108
Reimbursements	0
Insurance Receivable, ending balance	782
2020 Zogg Fire
Insurance Receivable [Roll Forward]
Insurance Receivable, beginning balance	219
Accrued insurance recoveries	108
Reimbursements	0
Insurance Receivable, ending balance	327
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_6

WILDFIRE-RELATED CONTINGENCIES (Regulatory Recovery) (Details) - 2017 Northern California wildfires $ in Millions	Jun. 04, 2021party	May 14, 2021party	May 11, 2021USD ($)	Mar. 23, 2021USD ($)	Apr. 30, 2020USD ($)
Loss Contingencies [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized			$ 7,500	$ 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
Number of parties whom filed for rehearing with company response (party) | party	2	3

WILDFIRE-RELATED CONTINGENCIE_7

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details) - Breach of Fiduciary Duties	Feb. 24, 2021claim	Nov. 20, 2017lawsuit	Nov. 16, 2017lawsuit
Loss Contingencies [Line Items]
Number of claims (claim) | claim	2
Derivative Lawsuits Filed in the San Francisco County Superior Court
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit		2	2

WILDFIRE-RELATED CONTINGENCIE_8

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation) (Details)	3 Months Ended
	Jul. 12, 2021claim	Mar. 17, 2021objection	Feb. 22, 2019offering	Dec. 31, 2018lawsuit	Jun. 30, 2018lawsuit
Loss Contingencies [Line Items]
Number of omnibus objection (objection) | objection		10
Wildfire-Related Class Action
Loss Contingencies [Line Items]
Number of lawsuits filed against company (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)				3
Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt | Subsequent event
Loss Contingencies [Line Items]
Number of subordinated claim (claim) | claim	2

WILDFIRE-RELATED CONTINGENCIE_9

WILDFIRE-RELATED CONTINGENCIES (De-energization Securities 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 CONTINGENCI_10

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_11

WILDFIRE-RELATED CONTINGENCIES (Wildfire Fund) (Details) - USD ($) $ in Millions	Jun. 24, 2021	Jul. 12, 2019	Jun. 30, 2021	May 11, 2021	Mar. 23, 2021	Feb. 24, 2021	Apr. 30, 2020
Commitments and Contingencies Disclosure [Abstract]
Disallowance cap, transmission and distribution equity rate base		$ 2,900
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
2017 Northern California wildfires
Loss Contingencies [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized				$ 7,500	$ 7,500		$ 7,500
2017 Northern California wildfires | Fire Risk Mitigation Capital Expenditures
Loss Contingencies [Line Items]
Customer Harm Threshold, post-emergence transaction, securitized	$ 1,190					$ 1,190
Recovery Bonds | 2017 Northern California wildfires | Fire Risk Mitigation Capital Expenditures
Loss Contingencies [Line Items]
Proceeds from issuance of debt	1,200
Debt issuance costs	$ 13.3

OTHER CONTINGENCIES AND COMMI_3

OTHER CONTINGENCIES AND COMMITMENTS (Order Instituting Investigation Narrative) (Details) $ in Millions	Jun. 30, 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	191
Disallowed capital, approved, cumulative charge, remaining portion	$ 7
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	Jun. 30, 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	Jul. 22, 2021petition	Sep. 21, 2018	Jun. 21, 2021petition	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%
Number of petitions for review to be consolidated (petition) | petition			2
Regulatory liabilities | $				$ 274
Regulatory assets | $				$ 150
Transmission Owner Rate Case Revenue | Subsequent event
Loss Contingencies [Line Items]
Number of petitions for review to be consolidated (petition) | petition	2
Petition review, pending substantive order duration	75 days
Pacific Gas & Electric Co (Utility) | 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	6 Months Ended
	Jun. 30, 2021USD ($)catastrophicEvent	Jul. 02, 2021USD ($)	Jan. 08, 2021USD ($)	Sep. 30, 2020USD ($)	May 04, 2020USD ($)	Aug. 07, 2019USD ($)	Apr. 25, 2019USD ($)	Mar. 30, 2018USD ($)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 | Subsequent event
Loss Contingencies [Line Items]
Revised cost recovery, decrease to revenue requirement per audit		$ 2.4
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	Jun. 30, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Accrued legal liabilities	$ 82	$ 134

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 (Gas Transmission and Storage Rate Case and Audit) (Details) - Disallowance of Plant Costs - USD ($) $ in Millions	Jul. 07, 2021	Jun. 23, 2016	Jun. 30, 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
2015 through 2022
Loss Contingencies [Line Items]
Capital expenditures for future recovery				$ 512
Capital expenditures for future recovery, seeking recovery				$ 416.3
Subsequent event | 2015 through 2022
Loss Contingencies [Line Items]
Capital expenditures for future recovery, pending authorization	$ 356.3
Subsequent event | 2015 through 2021
Loss Contingencies [Line Items]
Capital expenditures for future recovery, pending authorization	$ 313.3
Capital expenditures for future recovery, pending authorization, amortization period	60 months
Subsequent event | 2022
Loss Contingencies [Line Items]
Capital expenditures for future recovery, pending authorization	$ 43
Capital expenditures for future recovery, pending authorization, amortization period	12 months

OTHER CONTINGENCIES AND COMM_10

OTHER CONTINGENCIES AND COMMITMENTS (Diablo Canyon Nuclear Power Plant) (Details) - Diablo Canyon - USD ($) $ in Millions	May 25, 2021	Dec. 08, 2020
Loss Contingencies [Line Items]
Public comment period		30 days
Litigation payment	$ 5.9

OTHER CONTINGENCIES AND COMM_11

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Liability) (Details) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Site Contingency [Line Items]
Former manufactured gas plant sites owned by the Utility or third parties	$ 681	$ 659
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	112	111
Fossil fuel-fired generation facilities and sites	75	96
Environmental Remediation Liability	1,292	1,301
Topock, Arizona
Site Contingency [Line Items]
Natural gas compressor station	295	303
Hinkley, California
Site Contingency [Line Items]
Natural gas compressor station	$ 129	$ 132

OTHER CONTINGENCIES AND COMM_12

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Jun. 30, 2021USD ($)
Commitments and Contingencies Disclosure [Abstract]
Amount of environmental loss accrual expected to be recovered	$ 999

OTHER CONTINGENCIES AND COMM_13

OTHER CONTINGENCIES AND COMMITMENTS (Station Sites, Gas Plants, Generation Facilities and Disposal Sites) (Details) $ in Millions	Jun. 30, 2021USD ($)
Topock Site
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 221
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	$ 137
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Amount of environmental loss actual expected to be recovered	$ 400
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	$ 53
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)	6 Months Ended	12 Months Ended
	Jun. 30, 2021USD ($)nuclear_generating_unit	Jun. 30, 2021USD ($)outage
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	$ 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	42,000,000
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Additional insurance coverage, loss	200,000,000	200,000,000
Amount of property damage coverage provided by NEIL	4,000,000	$ 4,000,000
Diablo Canyon Outage
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	$ 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	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	$ 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 and Sale of SFGO) (Details) ft² in Thousands, $ in Millions	Jul. 22, 2021USD ($)	May 21, 2021	Oct. 23, 2020USD ($)	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
Office space
Loss Contingencies [Line Items]
Sale of building, duration after approval of sale		10 days
Office space | Subsequent event
Loss Contingencies [Line Items]
Proceeds from sale of buildings	$ 800
Escrow deposits related to property sales	$ 20