PG&E (PCG) 10-Q 7 Nov 19 2019 Q3 Quarterly report Financial data

Cover Page

Cover Page - shares	9 Months Ended
	Sep. 30, 2019	Nov. 01, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2019
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)		529,229,517
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001004980
Current Fiscal Year End Date	--12-31
Pacific Gas & Electric Co
Entity Information [Line Items]
Entity File Number	1-2348
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Incorporation, State or Country Code	CA
Entity Tax Identification Number	94-0742640
Entity Address, Address Line One	77 Beale Street
Entity Address, Address Line Two	P.O. Box 770000
Entity Address, City or Town	San Francisco,
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	94177
City Area Code	415
Local Phone Number	973-7000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		264,374,809
Amendment Flag	false
Entity Central Index Key	0000075488
The New York Stock Exchange | Common stock, no par value
Entity Information [Line Items]
Title of 12(b) Security	Common stock, no par value
Trading Symbol	PCG
Security Exchange Name	NYSE
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		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Operating Revenues
Total operating revenues	$ 4,432	$ 4,381	$ 12,386	$ 12,671
Operating Expenses
Operating and maintenance	2,206	1,611	6,235	5,001
Wildfire-related claims, net of insurance recoveries	2,548	(10)	6,448	2,108
Depreciation, amortization, and decommissioning	840	759	2,433	2,257
Total operating expenses	6,732	3,685	18,137	12,841
Operating Income (Loss)	(2,300)	696	(5,751)	(170)
Interest income	18	14	62	35
Interest expense	(52)	(232)	(215)	(678)
Other income, net	62	104	199	318
Reorganization items, net	(73)	0	(256)	0
Income (Loss) Before Income Taxes	(2,345)	582	(5,961)	(495)
Income tax provision (benefit)	(729)	15	(1,932)	(527)
Net Income (Loss)	(1,616)	567	(4,029)	32
Preferred stock dividend requirement of subsidiary	3	3	10	10
Income (Loss) Attributable to Common Shareholders	$ (1,619)	$ 564	$ (4,039)	$ 22
Weighted Average Common Shares Outstanding, Basic (in shares)	529	517	528	516
Weighted Average Common Shares Outstanding, Diluted (in shares)	529	517	528	517
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ (3.06)	$ 1.09	$ (7.65)	$ 0.04
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ (3.06)	$ 1.09	$ (7.65)	$ 0.04
Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	$ 4,432	$ 4,382	$ 12,386	$ 12,672
Operating Expenses
Operating and maintenance	2,208	1,611	6,252	5,002
Wildfire-related claims, net of insurance recoveries	2,548	(10)	6,448	2,108
Depreciation, amortization, and decommissioning	840	759	2,433	2,257
Total operating expenses	6,734	3,685	18,154	12,842
Operating Income (Loss)	(2,302)	697	(5,768)	(170)
Interest income	18	14	61	34
Interest expense	(52)	(229)	(213)	(668)
Other income, net	57	103	187	321
Reorganization items, net	(69)	0	(237)	0
Income (Loss) Before Income Taxes	(2,348)	585	(5,970)	(483)
Income tax provision (benefit)	(738)	14	(1,943)	(530)
Net Income (Loss)	(1,610)	571	(4,027)	47
Preferred stock dividend requirement of subsidiary	3	3	10	10
Income (Loss) Attributable to Common Shareholders	(1,613)	568	(4,037)	37
Electric
Operating Revenues
Total operating revenues	3,554	3,466	9,292	9,729
Operating Expenses
Cost of goods	1,070	1,256	2,506	3,038
Electric | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	3,554	3,467	9,292	9,730
Operating Expenses
Cost of goods	1,070	1,256	2,506	3,038
Natural gas
Operating Revenues
Total operating revenues	878	915	3,094	2,942
Operating Expenses
Cost of goods	68	69	515	437
Natural gas | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	878	915	3,094	2,942
Operating Expenses
Cost of goods	$ 68	$ 69	$ 515	$ 437

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Net Income (Loss)	$ (1,616)	$ 567	$ (4,029)	$ 32
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	0	1	0	1
Total other comprehensive income	0	1	0	1
Comprehensive Income (Loss)	(1,616)	568	(4,029)	33
Preferred stock dividend requirement of subsidiary	3	3	10	10
Comprehensive Income (Loss) Attributable to Common Shareholders	(1,619)	565	(4,039)	23
Pacific Gas & Electric Co
Net Income (Loss)	(1,610)	571	(4,027)	47
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	0	0	0	1
Total other comprehensive income	0	0	0	1
Comprehensive Income (Loss)	$ (1,610)	$ 571	$ (4,027)	$ 48

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Pacific Gas & Electric Co
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 2,970	$ 1,668
Accounts receivable:
Customers (net of allowance for doubtful accounts of $41 and $56 at respective dates)	1,397	1,148
Accrued unbilled revenue	1,023	1,000
Regulatory balancing accounts	1,919	1,435
Other	2,627	2,686
Regulatory assets	314	233
Inventories:
Gas stored underground and fuel oil	110	111
Materials and supplies	525	443
Income taxes receivable	15	23
Other	677	448
Total current assets	11,577	9,195
Property, Plant, and Equipment
Electric	61,797	59,150
Gas	22,741	21,556
Construction work in progress	2,689	2,564
Other	20	2
Total property, plant, and equipment	87,247	83,272
Accumulated depreciation	(25,923)	(24,715)
Net property, plant, and equipment	61,324	58,557
Other Noncurrent Assets
Regulatory assets	5,711	4,964
Nuclear decommissioning trusts	3,061	2,730
Operating lease right of use asset	2,435
Income taxes receivable	67	69
Other	1,538	1,480
Total other noncurrent assets	12,812	9,243
TOTAL ASSETS	85,713	76,995
Current Liabilities
Short-term borrowings	0	3,435
Long-term debt, classified as current	0	18,559
Accounts payable:
Trade creditors	1,844	1,975
Regulatory balancing accounts	1,655	1,076
Other	558	464
Operating lease liabilities	553
Disputed claims and customer refunds	0	220
Interest payable	5	228
Wildfire-related claims	0	14,226
Other	1,857	1,512
Total current liabilities	6,472	41,695
Noncurrent Liabilities
Debtor-in-possession financing	1,500	0
Regulatory liabilities	9,336	8,539
Pension and other post-retirement benefits	1,986	2,119
Asset retirement obligations	6,259	5,994
Deferred income taxes	1,721	3,281
Operating lease liabilities	1,882
Other	2,473	2,464
Total noncurrent liabilities	25,157	22,397
Liabilities Subject to Compromise	45,093	0
Shareholders’ Equity
Common stock	13,027	12,910
Reinvested earnings	(4,279)	(250)
Accumulated other comprehensive loss	(9)	(9)
Total shareholders’ equity	8,739	12,651
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	8,991	12,903
TOTAL LIABILITIES AND EQUITY	85,713	76,995
Pacific Gas & Electric Co
Current Assets
Cash and cash equivalents	2,539	1,295
Accounts receivable:
Customers (net of allowance for doubtful accounts of $41 and $56 at respective dates)	1,397	1,148
Accrued unbilled revenue	1,023	1,000
Regulatory balancing accounts	1,919	1,435
Other	2,639	2,688
Regulatory assets	314	233
Inventories:
Gas stored underground and fuel oil	110	111
Materials and supplies	525	443
Income taxes receivable	4	5
Other	666	448
Total current assets	11,136	8,806
Property, Plant, and Equipment
Electric	61,797	59,150
Gas	22,741	21,556
Construction work in progress	2,689	2,564
Other	18	0
Total property, plant, and equipment	87,245	83,270
Accumulated depreciation	(25,920)	(24,713)
Net property, plant, and equipment	61,325	58,557
Other Noncurrent Assets
Regulatory assets	5,711	4,964
Nuclear decommissioning trusts	3,061	2,730
Operating lease right of use asset	2,427
Income taxes receivable	66	66
Other	1,394	1,348
Total other noncurrent assets	12,659	9,108
TOTAL ASSETS	85,120	76,471
Current Liabilities
Short-term borrowings	0	3,135
Long-term debt, classified as current	0	18,209
Accounts payable:
Trade creditors	1,841	1,972
Regulatory balancing accounts	1,655	1,076
Other	650	498
Operating lease liabilities	550
Disputed claims and customer refunds	0	220
Interest payable	5	227
Wildfire-related claims	0	14,226
Other	1,857	1,497
Total current liabilities	6,558	41,060
Noncurrent Liabilities
Debtor-in-possession financing	1,500	0
Regulatory liabilities	9,336	8,539
Pension and other post-retirement benefits	1,986	2,026
Asset retirement obligations	6,259	5,994
Deferred income taxes	1,839	3,405
Operating lease liabilities	1,877
Other	2,528	2,492
Total noncurrent liabilities	25,325	22,456
Liabilities Subject to Compromise	44,309	0
Shareholders’ Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,550	8,550
Reinvested earnings	(1,201)	2,826
Accumulated other comprehensive loss	(1)	(1)
Total shareholders’ equity	8,928	12,955
TOTAL LIABILITIES AND EQUITY	$ 85,120	$ 76,471

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Allowance for doubtful accounts	$ 41	$ 56
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	529,229,517	520,338,710
Pacific Gas & Electric Co
Allowance for doubtful accounts	$ 41	$ 56
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	264,374,809	264,374,809

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash Flows from Operating Activities
Net income (loss)	$ (4,029)	$ 32
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,433	2,257
Allowance for equity funds used during construction	(64)	(97)
Deferred income taxes and tax credits, net	(1,548)	10
Reorganization items, net (Note 2)	97	0
Disallowed capital expenditures	232	(38)
Other	112	231
Effect of changes in operating assets and liabilities:
Accounts receivable	(264)	(201)
Wildfire-related insurance receivable	35	64
Inventories	(68)	(24)
Accounts payable	371	245
Wildfire-related claims	(114)	2,233
Income taxes receivable/payable	8	0
Other current assets and liabilities	(7)	(154)
Regulatory assets, liabilities, and balancing accounts, net	90	(128)
Liabilities subject to compromise	6,704	0
Other noncurrent assets and liabilities	79	(194)
Net cash provided by operating activities	4,067	4,236
Cash Flows from Investing Activities
Capital expenditures	(4,192)	(4,592)
Proceeds from sales and maturities of nuclear decommissioning trust investments	808	1,121
Purchases of nuclear decommissioning trust investments	(874)	(1,165)
Other	8	19
Net cash used in investing activities	(4,250)	(4,617)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850	0
Repayments of debtor-in-possession credit facility	(350)	0
Debtor-in-possession credit facility debt issuance costs	(114)	0
Borrowings under revolving credit facilities	0	775
Repayments under revolving credit facilities	0	(775)
Net repayments of commercial paper, net of discount	0	(182)
Short-term debt financing	0	250
Short-term debt matured	0	(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7	0	1,143
Long-term debt matured or repurchased	0	(750)
Common stock issued	85	137
Other	14	14
Net cash provided by financing activities	1,485	362
Net change in cash, cash equivalents, and restricted cash	1,302	(19)
Cash, cash equivalents, and restricted cash at January 1	1,675	456
Cash, cash equivalents, and restricted cash at September 30	2,977	437
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)	(7)
Cash and cash equivalents	2,970	430
Cash paid for:
Interest, net of amounts capitalized	(38)	(650)
Income taxes, net	0	(49)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	2,816	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	981	348
Pacific Gas & Electric Co
Cash Flows from Operating Activities
Net income (loss)	(4,027)	47
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,433	2,257
Allowance for equity funds used during construction	(64)	(97)
Deferred income taxes and tax credits, net	(1,555)	5
Reorganization items, net (Note 2)	92	0
Other	79	170
Effect of changes in operating assets and liabilities:
Accounts receivable	(274)	(200)
Wildfire-related insurance receivable	35	64
Inventories	(68)	(24)
Accounts payable	418	245
Wildfire-related claims	(114)	2,233
Income taxes receivable/payable	1	0
Other current assets and liabilities	9	(156)
Regulatory assets, liabilities, and balancing accounts, net	90	(128)
Liabilities subject to compromise	6,695	0
Other noncurrent assets and liabilities	96	(194)
Net cash provided by operating activities	4,078	4,184
Cash Flows from Investing Activities
Capital expenditures	(4,192)	(4,592)
Proceeds from sales and maturities of nuclear decommissioning trust investments	808	1,121
Purchases of nuclear decommissioning trust investments	(874)	(1,165)
Other	8	19
Net cash used in investing activities	(4,250)	(4,617)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850	0
Repayments of debtor-in-possession credit facility	(350)	0
Debtor-in-possession credit facility debt issuance costs	(98)	0
Borrowings under revolving credit facilities	0	650
Repayments under revolving credit facilities	0	(650)
Net repayments of commercial paper, net of discount	0	(50)
Short-term debt financing	0	250
Short-term debt matured	0	(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7	0	793
Long-term debt matured or repurchased	0	(400)
Other	14	14
Net cash provided by financing activities	1,416	357
Net change in cash, cash equivalents, and restricted cash	1,244	(76)
Cash, cash equivalents, and restricted cash at January 1	1,302	454
Cash, cash equivalents, and restricted cash at September 30	2,546	378
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)	(7)
Cash and cash equivalents	2,539	371
Cash paid for:
Interest, net of amounts capitalized	(36)	(640)
Income taxes, net	0	(59)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	2,807	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$ 981	$ 348

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Discount on net issuances of commercial paper	$ 1
Debt discount and issuance costs	7
Pacific Gas & Electric Co
Debt discount and issuance costs	$ 7

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	Pacific Gas & Electric CoPreferred Stock	Pacific Gas & Electric CoCommon Stock	Pacific Gas & Electric CoAdditional Paid-in Capital	Pacific Gas & Electric CoReinvested Earnings	Pacific Gas & Electric CoAccumulated Other Comprehensive Income (Loss)	Pacific Gas & Electric CoTotal Shareholders’ Equity
Beginning balance (in shares) at Dec. 31, 2017		514,755,845
Beginning balance at Dec. 31, 2017	$ 19,472	$ 12,632	$ 6,596	$ (8)	$ 19,220	$ 252		$ 258	$ 1,322	$ 8,505	$ 9,656	$ 6	$ 19,747
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	445		445		445						452		452
Other comprehensive income (loss)			5	(5)							2	(2)
Common stock issued, net (in shares)		1,248,112
Common stock issued, net	35	$ 35			35
Stock-based compensation amortization	34	$ 34			34
Preferred stock dividend requirement of subsidiary	(3)		(3)		(3)
Preferred stock dividend											(3)		(3)
Ending balance (in shares) at Mar. 31, 2018		516,003,957
Ending balance at Mar. 31, 2018	19,983	$ 12,701	7,043	(13)	19,731	252		258	1,322	8,505	10,107	4	20,196
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	445		445		445						452		452
Beginning balance (in shares) at Dec. 31, 2017		514,755,845
Beginning balance at Dec. 31, 2017	19,472	$ 12,632	6,596	(8)	19,220	252		258	1,322	8,505	9,656	6	19,747
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	32						$ 47
Ending balance (in shares) at Sep. 30, 2018		518,332,824
Ending balance at Sep. 30, 2018	19,696	$ 12,833	6,623	(12)	19,444	252		258	1,322	8,505	9,695	5	19,785
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	32						47
Beginning balance (in shares) at Mar. 31, 2018		516,003,957
Beginning balance at Mar. 31, 2018	19,983	$ 12,701	7,043	(13)	19,731	252		258	1,322	8,505	10,107	4	20,196
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(980)		(980)		(980)						(976)		(976)
Other comprehensive income (loss)												1	1
Common stock issued, net (in shares)		1,099,026
Common stock issued, net	47	$ 47			47
Stock-based compensation amortization	15	$ 15			15
Preferred stock dividend requirement of subsidiary	(4)		(4)		(4)
Preferred stock dividend											(4)	0	(4)
Ending balance (in shares) at Jun. 30, 2018		517,102,983
Ending balance at Jun. 30, 2018	19,061	$ 12,763	6,059	(13)	18,809	252		258	1,322	8,505	9,127	5	19,217
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(980)		(980)		(980)						(976)		(976)
Net income (loss)	567		567		567		571				571		571
Other comprehensive income (loss)	1			1	1
Common stock issued, net (in shares)		1,229,841
Common stock issued, net	55	$ 55			55
Stock-based compensation amortization	15	$ 15			15
Preferred stock dividend requirement of subsidiary	(3)		(3)		(3)
Preferred stock dividend											(3)	0	(3)
Ending balance (in shares) at Sep. 30, 2018		518,332,824
Ending balance at Sep. 30, 2018	19,696	$ 12,833	6,623	(12)	19,444	252		258	1,322	8,505	9,695	5	19,785
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 567		567		567		$ 571				571		571
Beginning balance (in shares) at Dec. 31, 2018	520,338,710	520,338,710					264,374,809
Beginning balance at Dec. 31, 2018	$ 12,903	$ 12,910	(250)	(9)	12,651	252		258	1,322	8,550	2,826	(1)	12,955
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	136		136		136						133		133
Common stock issued, net (in shares)		8,871,568
Common stock issued, net	85	$ 85			85
Stock-based compensation amortization	5	$ 5			5
Ending balance (in shares) at Mar. 31, 2019		529,210,278
Ending balance at Mar. 31, 2019	13,129	$ 13,000	(114)	(9)	12,877	252		258	1,322	8,550	2,959	(1)	13,088
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 136		136		136						133		133
Beginning balance (in shares) at Dec. 31, 2018	520,338,710	520,338,710					264,374,809
Beginning balance at Dec. 31, 2018	$ 12,903	$ 12,910	(250)	(9)	12,651	252		258	1,322	8,550	2,826	(1)	12,955
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (4,029)						$ (4,027)
Ending balance (in shares) at Sep. 30, 2019	529,229,517	529,229,517					264,374,809
Ending balance at Sep. 30, 2019	$ 8,991	$ 13,027	(4,279)	(9)	8,739	252		258	1,322	8,550	(1,201)	(1)	8,928
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(4,029)						$ (4,027)
Beginning balance (in shares) at Mar. 31, 2019		529,210,278
Beginning balance at Mar. 31, 2019	13,129	$ 13,000	(114)	(9)	12,877	252		258	1,322	8,550	2,959	(1)	13,088
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(2,549)		(2,549)		(2,549)						(2,550)		(2,550)
Common stock issued, net (in shares)		13,515
Stock-based compensation amortization	14	$ 14			14
Ending balance (in shares) at Jun. 30, 2019		529,223,793
Ending balance at Jun. 30, 2019	10,594	$ 13,014	(2,663)	(9)	10,342	252		258	1,322	8,550	409	(1)	10,538
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(2,549)		(2,549)		(2,549)						(2,550)		(2,550)
Net income (loss)	(1,616)		(1,616)		(1,616)		$ (1,610)				(1,610)		(1,610)
Common stock issued, net (in shares)		5,724
Stock-based compensation amortization	$ 13	$ 13			13
Ending balance (in shares) at Sep. 30, 2019	529,229,517	529,229,517					264,374,809
Ending balance at Sep. 30, 2019	$ 8,991	$ 13,027	(4,279)	$ (9)	8,739	$ 252		$ 258	$ 1,322	$ 8,550	(1,201)	$ (1)	8,928
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (1,616)		$ (1,616)		$ (1,616)		$ (1,610)				$ (1,610)		$ (1,610)

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 as 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, 2018 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2018 Form 10-K. This quarterly report should be read in conjunction with the 2018 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, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, pension and other post-retirement benefit plan obligations, and the valuation of LSTC. 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 and results of operations during the period in which such change occurred. Chapter 11 Filing and Going Concern The accompanying Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. See Note 10 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. PG&E Corporation and the Utility determined that commencing reorganization cases under Chapter 11 was necessary to restore PG&E Corporation’s and the Utility’s financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation’s and the Utility’s financial stability. On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. The Condensed Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns. Pursuant to sections 1107(a) and 1108 of the Bankruptcy Code, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors-in-possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation’s and the Utility’s DIP Credit Agreement (see Note 5 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Condensed Consolidated Financial Statements. Any such actions occurring during the Chapter 11 Cases authorized by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. (For more information regarding the Chapter 11 Cases, see Note 2 below.)

BANKRUPTCY FILING

BANKRUPTCY FILING	9 Months Ended
	Sep. 30, 2019
Reorganizations [Abstract]
BANKRUPTCY FILING	BANKRUPTCY FILING Chapter 11 Proceedings On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. PG&E Corporation and the Utility continue 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. Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 10 below) as of the Petition Date, are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be resolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and interest holders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings generally are not subject to an automatic stay, and these proceedings have been continuing during the pendency of the Chapter 11 Cases. Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation's and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests. Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this quarterly report on Form 10-Q, or in the 2018 Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code. Significant Bankruptcy Court Actions First Day Motions On January 31, 2019, the Bankruptcy Court approved, on an interim basis, certain motions (the “First Day Motions”) authorizing, but not directing, PG&E Corporation and the Utility to, among other things, (a) secure $5.5 billion of debtor-in-possession financing; (b) continue to use PG&E Corporation’s and the Utility’s cash management system; and (c) pay certain pre-petition claims relating to (i) certain safety, reliability, outage, and nuclear facility suppliers; (ii) shippers, warehousemen, and other lien claimants; (iii) taxes; (iv) employee wages, salaries, and other compensation and benefits; and (v) customer programs, including public purpose programs. The First Day Motions were subsequently approved by the Bankruptcy Court on a final basis at hearings on February 27, 2019, March 12, 2019, March 13, 2019, and March 27, 2019. Exclusivity Period On May 23, 2019, the Bankruptcy Court entered an order (the “Exclusivity Order”) pursuant to section 1121(d) of the Bankruptcy Code, extending PG&E Corporation’s and the Utility’s exclusive periods in which to file a Chapter 11 plan of reorganization (the “Exclusive Filing Period”) and solicit acceptances thereof (the “Exclusive Solicitation Period” and, together with the Exclusive Filing Period, the “Exclusive Periods”). Pursuant to the Exclusivity Order, PG&E Corporation’s and the Utility’s Exclusive Filing Period was extended to, and including, September 26, 2019, and PG&E Corporation’s and the Utility’s Exclusive Solicitation Period was extended to, and including, November 26, 2019. On June 25, 2019, the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility (the “Ad Hoc Noteholder Committee”) submitted a motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, for the entry of an order terminating the Exclusive Periods. The Ad Hoc Noteholder Committee annexed to its motion a “Term Sheet for Plan of Reorganization,” which was thereafter amended on July 17, 2019. On July 18, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court, requesting that the motion be denied. On July 23, 2019, the Ad Hoc Group of Subrogation Claim Holders (the “Ad Hoc Subrogation Group”) submitted its own motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, to terminate the Exclusive Periods, which included as an exhibit a “Restructuring Term Sheet.” On August 6, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Subrogation Group’s motion with the Bankruptcy Court, requesting that the motion be denied. On August 16, 2019, the Bankruptcy Court issued a decision in which it denied the Ad Hoc Noteholder Committee’s and the Ad Hoc Subrogation Group’s motions to terminate exclusivity. As discussed in Note 10, on the same date, the Bankruptcy Court granted the motions to lift the automatic stay as applied to certain claims arising out of the 2017 Tubbs fire to allow a state court jury trial on those claims (the “Lift Stay Decision”). On September 19, 2019, the TCC and the Ad Hoc Noteholder Committee filed a joint motion to terminate PG&E Corporation’s and the Utility’s Exclusive Periods, which included as an exhibit a “Term Sheet for Plan of Reorganization.” On September 25, 2019, PG&E Corporation and the Utility filed a motion seeking a further extension of their Exclusive Periods pursuant to section 1121(d) of the Bankruptcy Code. Also on September 25, 2019, the TCC and Ad Hoc Noteholder Committee filed an amended plan term sheet, which amended the term sheet previously annexed to their joint motion. The term sheet was further amended on October 4, 2019. PG&E Corporation and the Utility filed an objection to the motion of the TCC and the Ad Hoc Noteholder Committee on October 4, 2019, requesting that the joint motion be denied. The hearing on the joint motion to terminate exclusivity filed by the TCC and the Ad Hoc Noteholder Committee was held on October 7, 2019. Following the hearing, on October 9, 2019, the Bankruptcy Court entered an order granting the motion of the TCC and the Ad Hoc Noteholder Committee to terminate the Exclusive Periods as to the TCC and the Ad Hoc Noteholder Committee (the “Exclusivity Termination Decision”). On that same date, the Bankruptcy Court entered an order denying the motion filed by PG&E Corporation and the Utility seeking a further extension of their Exclusive Periods. On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed their competing Chapter 11 plan of reorganization (the “TCC/Ad Hoc Noteholder Plan”). See “TCC/Ad Hoc Noteholder Plan of Reorganization” below. Upcoming Legal Briefings A status conference on the TCC/Ad Hoc Noteholder Plan and the Proposed Plan (as described below) was held on October 23, 2019, at which the Bankruptcy Court established a tentative briefing schedule on certain legal issues and postponed consideration of PG&E Corporation’s and the Utility’s motion to approve the RSA (as described below) to November 13, 2019. On October 31, 2019, the Bankruptcy Court entered an order setting the final briefing and hearing schedule on certain legal issues in the Chapter 11 Cases. The hearings on the various legal issues are scheduled as follows: • on the application of the doctrine of inverse condemnation: November 19, 2019; • on the issue of post-petition interest rate applicable on unsecured claims: December 11, 2019; • on whether the claims asserted by the U.S. Government, certain California state agencies and certain other entities are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code: December 17, 2019; • on whether holders of the Utility’s funded debt claims are entitled to any make-whole or optional redemption or similar amounts: January 14, 2020; and • on whether the Subrogation Claims that are settled and allowed as provided in the Subrogation Claims Settlement (described below) are impaired: January 14, 2020. Bar Date On July 1, 2019, the Bankruptcy Court entered an order approving a deadline of October 21, 2019, at 5:00 p.m. (Pacific Time) (the “Bar Date”) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the Bar Date for which occurred on April 22, 2019. The Bankruptcy Court also approved PG&E Corporation’s and the Utility’s plan to provide notice of the Bar Date to parties in interest, including potential wildfire-related claimants and other potential creditors. On October 18, 2019, the TCC filed with the Bankruptcy Court a motion for entry of an order extending the Bar Date for individual wildfire-related claims. On October 28, 2019, PG&E Corporation and the Utility announced that they had offered to extend the Bar Date for individual wildfire-related claims from October 21, 2019 to December 20, 2019. On the same day, during a meet and confer between PG&E Corporation and the Utility and the TCC, and at the request of the TCC, PG&E Corporation and the Utility agreed to further extend the Bar Date for individual wildfire-related claims to December 31, 2019. On November 4, 2019, PG&E Corporation and the Utility and the TCC announced that they have reached agreement to an extension of the Bar Date for individual wildfire-related claims to December 31, 2019, which agreement also involves procedures for additional notice to potential individual wildfire claimants. PG&E Corporation and the Utility and the TCC will file a stipulation with the Bankruptcy Court detailing the terms of the agreement and seeking approval of their agreement. Other Significant Actions Related to the Chapter 11 Cases Other significant actions and developments related to the Chapter 11 Cases, including the Tubbs Lift Stay Decision, the Tubbs Trial and the Estimation Proceeding are described in Note 10 (including under the headings “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” and “Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California”). On October 28, 2019, the Bankruptcy Court issued an order directing the principal parties in the Chapter 11 Cases to participate in mediation. The mediator is retired Bankruptcy Court Judge Randall Newsome. Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters On September 9, 2019, PG&E Corporation and the Utility filed with the Bankruptcy Court their Joint Chapter 11 Plan of Reorganization (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the resolution of the outstanding pre-petition claims against and interests in PG&E Corporation and the Utility. On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”). On November 1, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors entered into an amended and restated Restructuring Support Agreement. The RSA provides for an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle all insurance subrogation claims (the “Subrogation Claims”) relating to the 2017 Northern California wildfires and the 2018 Camp fire (the “Subrogation Claims Settlement”), upon the terms and conditions set forth in the RSA. Under the RSA, PG&E Corporation and the Utility also have agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the RSA. On September 23, 2019, in accordance with the RSA, PG&E Corporation and the Utility filed their First Amended Joint Chapter 11 Plan of Reorganization to incorporate the terms of the Subrogation Claims Settlement. On November 4, 2019, in accordance with the RSA, as amended, PG&E Corporation and the Utility filed their Joint Chapter 11 Plan of Reorganization dated November 4, 2019. The Proposed Plan, as amended, proposes the following: • compensation of wildfire victims and certain public entities from a trust funded for their benefit in an amount to be determined in an estimation proceeding not to exceed $8.4 billion; • compensation of insurance subrogation claimants from a trust funded for their benefit in the amount of $11.0 billion in accordance with the terms of the Subrogation Claims Settlement and RSA; • payment of $1.0 billion in full settlement of the claims of the settling public entities relating to the wildfires (as further described under the heading “Plan Support Agreements with Public Entities” in Note 10); • payment in full, with interest at the federal judgment rate, of all pre-petition funded debt obligations, all pre-petition trade claims and all pre-petition employee-related unsecured claims; • assumption of all power purchase agreements and community choice aggregation servicing agreements; • assumption of all pension obligations, other employee obligations, and collective bargaining agreements with labor; • future participation in the state wildfire fund established by AB 1054; and • satisfaction of the requirements of AB 1054. The Proposed Plan, as amended, proposes the following key financing sources: • one or more equity offerings of up to $14 billion, in accordance with the Backstop Commitment Letters (as described below); and • permanent financing in the form of bank facilities, debt securities or a combination of the foregoing in the amount of $27.35 billion at the Utility and $7.0 billion at PG&E Corporation, which would be in lieu of the Facilities (as described below). Additional sources of financing are expected to include insurance proceeds in connection with the 2015 Butte fire, 2017 Northern California wildfires and the 2018 Camp fire. The Proposed Plan, as amended, has not been approved and may be further amended, modified, or supplemented as necessary or desired by PG&E Corporation and the Utility or as required by the Bankruptcy Court or the CPUC. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the RSA and approval of the Subrogation Claims Settlement. Pursuant to that motion, PG&E Corporation and the Utility requested that the allowance of the Subrogation Claims in the aggregate amount of $11.0 billion be effective upon the approval of the motion and that the treatment and satisfaction of the Subrogation Claims be effectuated pursuant to the Proposed Plan following confirmation of the effectiveness of the Proposed Plan. Various stakeholders filed objections to PG&E Corporation's and the Utility's motion, including the UCC, the Ad Hoc Noteholder Committee, the TCC and the U.S. Government. A hearing on PG&E Corporation’s and the Utility’s motion to approve the RSA was held on October 23, 2019, at which the Bankruptcy Court continued the hearing on the motion to November 13, 2019. On November 2, 2019, PG&E Corporation and the Utility filed the RSA, as amended, with the Bankruptcy Court. Equity Backstop Commitments As of September 30, 2019, PG&E Corporation has entered into Chapter 11 Plan Backstop Commitment Letters (collectively, the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $14.0 billion of proceeds to finance the Proposed Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). The price at which any such new shares would be issued to the Backstop Parties would be equal to (a) 10 (subject to adjustment as provided in the Backstop Commitment Letters), times (b) PG&E Corporation’s consolidated Normalized Estimated Net Income (as defined in the Backstop Commitment Letters) for the estimated year 2021, divided by (c) the number of fully diluted shares of PG&E Corporation that will be outstanding on the effective date of the Proposed Plan (the “Effective Date”) (assuming that all equity is raised by funding the Backstop Commitments). The Backstop Commitment Letters provide that, under certain circumstances, PG&E Corporation and the Utility will be permitted to issue new shares of common stock of PG&E Corporation for up to $14.0 billion of proceeds to finance the transactions contemplated by the Proposed Plan through one or more equity offerings that, under certain circumstances, must include a rights offering (the “Rights Offering”). The structure, terms and conditions of any such equity offering (including a Rights Offering) are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. This may include terms and conditions that are designed to preserve the ability of PG&E Corporation or the Utility to utilize their net operating loss carryforwards. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $14.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Proposed Plan, subject to the satisfaction or waiver by the Backstop Parties of the conditions set forth therein. The Backstop Parties’ funding obligations under the Backstop Commitment Letters are subject to numerous conditions, including, among others, that (a) the Backstop Commitment Letters have been approved by the Bankruptcy Court on or before November 20, 2019, (b) the conditions precedent to the Effective Date set forth in the Proposed Plan have been satisfied or waived in accordance with the Proposed Plan, (c) the Bankruptcy Court has entered an order confirming the Proposed Plan and approving the transactions contemplated thereunder, which shall confirm the Proposed Plan with such amendments, modifications, changes and consents as are approved by holders of a majority of the Backstop Commitments (the “Confirmation Order”), (d) PG&E Corporation’s and the Utility’s weighted average earning rate base for 2021 is no less than 95% of $48 billion and (e) there has been no event, occurrence or other circumstance that would have or would reasonably be expected to have a material adverse effect on the business of PG&E Corporation and the Utility or their ability to consummate the transactions contemplated by the Backstop Commitment Letters and the Proposed Plan. PG&E Corporation intends to seek an extension of the deadline to obtain Bankruptcy Court approval of the Backstop Commitment Letters. In addition, the Backstop Parties have certain termination rights under the Backstop Commitment Letters. The Backstop Parties may terminate the Backstop Commitment Letters if PG&E Corporation’s and the Utility’s aggregate liability with respect to pre-petition wildfire-related claims exceeds $18.9 billion (the “Wildfire Claims Cap”) (without counting wildfire-related claims that are approved by the CPUC for recovery or pass-through against such cap), which cap may be adjusted upward for wildfire-related claims consisting of professional fees that the Bankruptcy Court (or the U.S. District Court for the Northern District of California (the “District Court”), if applicable) determines to be reasonable. The Backstop Parties’ other termination rights include, among others, if (i) the Proposed Plan is amended without the consent of the holders of a majority of the Backstop Commitments, (ii) the Confirmation Order has not been entered by June 30, 2020, (iii) the Effective Date has not occurred within 60 days of entry of the Confirmation Order, (iv) a material adverse effect (as described above) occurs, (v) wildfires occur in the Utility’s service area in 2019 that damage or destroy in excess of 500 dwellings or commercial structures in the aggregate, (vi) the CPUC fails to issue all necessary approvals, authorizations and final orders to implement the Proposed Plan prior to June 30, 2020, including approvals related to the Utility’s capital structure and authorized rate of return and the resolution of the CPUC’s claims against the Utility for fines or penalties, all of which must be satisfactory to the holders of a majority of the Backstop Commitments, (vii) asserted administrative expense claims in the Chapter 11 Cases exceed $250 million (subject to certain exceptions), (viii) one or more wildfires occur in the Utility’s service area during or after 2020 that damage or destroy at least 500 dwellings or commercial structures in the aggregate at a time when the portion of the Utility’s system at the location of such wildfire was not successfully de-energized, and (ix) the Utility has not elected and received Bankruptcy Court approval, or satisfied the other required conditions, to participate in the statewide wildfire fund established by AB 1054. There can be no assurance that the conditions precedent set forth in the Backstop Commitment Letters will be satisfied or waived, nor that events or circumstances will not occur that give rise to termination rights of the Backstop Parties. In connection with PG&E Corporation’s and the Utility’s entry into the RSA as described above, if the Bankruptcy Court does not approve the RSA on or prior to November 20, 2019, then the Backstop Commitment Letters provide that (i) the Wildfire Claims Cap will be reduced to $17.9 billion (without counting wildfire-related claims that are approved by the CPUC for recovery or pass-through against such cap), which cap may be adjusted upward for wildfire-related claims consisting of professional fees that the Bankruptcy Court (or the District Court, if applicable) determines to be reasonable, and (ii) the Proposed Plan must be amended to remove any Permitted Amendments (as defined in the Backstop Commitment Letters). The initial commitment premium for the Backstop Commitments is 0.75% of the amount of the Backstop Commitments. The initial term of the Backstop Commitment Letters expires on January 20, 2020. PG&E Corporation and the Utility can extend the term of the Backstop Commitment Letters to April 30, 2020 for an additional commitment premium of 1.25% of the amount of the Backstop Commitments, to June 30, 2020 for an additional commitment premium of 2.5% of the amount of the Backstop Commitments and to August 29, 2020 for an additional commitment premium of 0.5% of the amount of the Backstop Commitments. All such commitment premiums are cumulative. Subject to limited exceptions, all commitment premiums are payable in shares of PG&E Corporation common stock to be issued on the Effective Date, and the number of such shares to be paid as commitment premiums will be calculated using the backstop price described above. In the event that a plan of reorganization for PG&E Corporation and the Utility that is not the Proposed Plan is confirmed by the Bankruptcy Court, then the backstop commitment premium will be payable in cash if elected by the applicable Backstop Party. Debt Commitment Letters On October 11, 2019, PG&E Corporation and the Utility entered into debt commitment letters (the “Debt Commitment Letters”) with JPMorgan Chase Bank, N.A., Bank of America, N.A., BofA Securities, Inc., Barclays Bank PLC, Citigroup Global Markets Inc., Goldman Sachs Bank USA, Goldman Sachs Lending Partners LLC and the other lenders that may become parties to the Debt Commitment Letters as additional “Commitment Parties” as provided therein (the foregoing parties, collectively, the “Commitment Parties”), pursuant to which the Commitment Parties committed to provide $34.35 billion in bridge financing in the form of (a) a $27.35 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy (the Utility or any such entity, the “OpCo Borrower”) as borrower thereunder and (b) a $7.0 billion senior unsecured bridge loan facility (together with the OpCo Facility, the “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy (the Corporation or any such entity, the "HoldCo Borrower") as borrower thereunder, subject to the terms and conditions set forth therein. The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights described below. Borrowings under the OpCo Facility would be senior secured obligations of the OpCo Borrower, secured by substantially all of the assets of the OpCo Borrower. Borrowings under the HoldCo Facility would be senior unsecured obligations of the HoldCo Borrower. The OpCo Borrower’s obligations under the OpCo Facility, and the HoldCo Borrower’s obligations under the HoldCo Facility, would not be guaranteed by any other entity. The scheduled maturity of each of the Facilities would be 364 days following the date the Facilities are funded. PG&E Corporation and the Utility will pay customary fees and expenses in connection with obtaining the Facilities. The Commitment Parties’ funding obligations under the Debt Commitment Letters are subject to numerous conditions and termination rights, including, among others, certain conditions and termination rights similar to those included in the Backstop Commitment Letters, in addition to conditions that are not in the Backstop Commitment Letters, including (a) the delivery of specified financial information, (b) PG&E Corporation’s receipt of at least $14.0 billion of proceeds from the issuance of equity, of which up to $2.0 billion may take the form of preferred equity, equity-linked securities or securitizations to the extent not negatively impacting cash distributions to PG&E Corporation or distributions that will be available to service debt at PG&E Corporation, (c) the execution of definitive documentation for the Facilities and (d) that the Utility shall have received investment grade senior secured debt ratings. In addition, the Debt Commitment Letters are subject to approval by the Bankruptcy Court on or before November 20, 2019, and the Utility’s ability to borrow under the OpCo Facility is subject to approval by the CPUC. PG&E Corporation and the Utility intend to seek an extension of the deadline to obtain Bankruptcy Court approval of the Debt Commitment Letters. In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the foregoing. On October 23, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking approval of the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters. The hearing on PG&E Corporation’s and the Utility’s motion to approve the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters is scheduled for November 19, 2019. The timing and outcome of the Chapter 11 Cases is uncertain. Although PG&E Corporation, the Utility, the Bankruptcy Court, the CPUC and many other stakeholders have stated that they are working towards confirming a plan of reorganization by June 30, 2020, it is possible that the Chapter 11 process could extend beyond the June 30, 2020 deadline and take a number of years to resolve. TCC/Ad Hoc Noteholder Plan of Reorganization On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed the TCC/Ad Hoc Noteholder Plan. The TCC/Ad Hoc Noteholder Plan differs from the Proposed Plan in a number of respects, including, but not limited to: • the TCC/Ad Hoc Noteholder Plan proposes a trust for payment of wildfire victim claims (other than insurance subrogation claims) funded with consideration in an amount equal to the lesser of (i) $14.5 billion (“at plan value”), of which $1.0 billion would be set aside in a separate trust for the Supporting Public Entities, and (ii) an amount of such claims as determined by a court of competent jurisdiction (with the form of such consideration to be an unspecified mix of cash and PG&E Corporation common stock (“at plan value”)); • the TCC/Ad Hoc Noteholder Plan proposes that holders of claims in respect of certain series of short-term senior notes of the Utility receive consideration consisting of (i) principal and accrued and unpaid pre-petition interest at the contract rate specified in the definitive documentation for each such series, (ii) accrued and unpaid post-petition interest at the contract rate specified in the definitive documentation for each such series and (iii) any prepayment premium, make-whole or other similar call protection specified in the definitive documentation for each such series; • the TCC/Ad Hoc Noteholder Plan proposes that the Utility’s other senior notes would be reinstated at emergence with holders receiving (i) accrued and unpaid pre-petition interest at the contract rate specified in the definitive documentation for each such series and (ii) accrued and unpaid post-petition interest at the contract rate specified in the definitive documentation for each such series; and • the TCC/Ad Hoc Noteholder Plan proposes the following significant financing sources: (i) $12.75 billion (“at plan value”) of newly issued PG&E Corporation common stock, representing 40.6% of the post-emergence PG&E Corporation common stock, would be issued to the trust for payment of wildfire victim claims and, if applicable, the trust for payment of insurance subrogation claims; (ii) members of the Ad Hoc Noteholder Committee, and potentially other third parties, would make a $15.5 billion investment in PG&E Corporation common stock, representing 59.3% of the post-emergence PG&E Corporation common stock, in order to fund the transactions contemplated by the TCC/Ad Hoc Noteholder Plan; and (iii) PG&E Corporation would issue $5.75 billion of new senior unsecured notes and the Utility would issue $8.0 billion of new senior secured notes, in each case to certain members of the Ad Hoc Noteholder Committee in order to fund the transactions contemplated by the TCC/Ad Hoc Noteholder Plan. The TCC/Ad Hoc Noteholder Plan has not been approved by the Bankruptcy Court or the CPUC and may be amended, modified, or supplemented as necessary or desired by the proponents thereof. Debtor-In-Possession Financing See Note 5 for further discussion of the DIP Facilities, which provide up to $5.5 billion in financing. Financial Reporting in Reorganization Effective on the Petition Date, PG&E Corporation and the Utility began to apply accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that are directly associated with reorganization proceedings must be reported separately as reorganization items, net in the Condensed Consolidated Statements of Income. In addition, the balance sheet must distinguish pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that are not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that are not debto

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2019
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 2 of the Condensed Consolidated Financial Statements above for bankruptcy-related policies and Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. Disallowance of Plant Costs PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. In the three and nine months ended September 30, 2019, PG&E Corporation and the Utility recorded $237 million for pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period. 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. 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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2019, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights 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 September 30, 2019, 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 nine months ended September 30, 2019 and 2018 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2019 2018 2019 2018 Service cost for benefits earned (1) $ 110 $ 128 $ 14 $ 16 Interest cost 189 171 19 17 Expected return on plan assets (226) (255) (31) (33) Amortization of prior service cost (1) (1) 3 4 Amortization of net actuarial loss 1 1 — (1) Net periodic benefit cost 73 44 5 3 Regulatory account transfer (2) 10 41 — — Total $ 83 $ 85 $ 5 $ 3 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (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 Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Service cost for benefits earned (1) $ 332 $ 385 $ 42 $ 49 Interest cost 568 515 57 52 Expected return on plan assets (679) (766) (92) (98) Amortization of prior service cost (4) (4) 10 11 Amortization of net actuarial loss 2 4 (2) (4) Net periodic benefit cost 219 134 15 10 Regulatory account transfer (2) 31 118 — — Total $ 250 $ 252 $ 15 $ 10 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (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. On February 27, 2019, PG&E Corporation and the Utility received final approval from the Bankruptcy Court to maintain existing pension and other benefit plans, other than the non-qualified pension plan, during the pendency of the Chapter 11 Cases. 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) are summarized below: Pension Other Total (in millions, net of income tax) Three Months Ended September 30, 2019 Beginning balance $ (21) $ 17 $ (4) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) 1 — 1 Regulatory account transfer (net of taxes of $0 and $1, respectively) — (2) (2) Net current period other comprehensive gain (loss) — — — Ending balance $ (21) $ 17 $ (4) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended September 30, 2018 Beginning balance $ (30) $ 17 $ (13) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $0, and $0, respectively) 1 (1) — Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 (2) (1) Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (29) $ 17 $ (12) (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 Other Total (in millions, net of income tax) Nine Months Ended September 30, 2019 Beginning balance $ (21) $ 17 $ (4) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $3, respectively) (3) 7 4 Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) 2 (1) 1 Regulatory account transfer (net of taxes of $1 and $2, respectively) 1 (6) (5) Net current period other comprehensive gain (loss) — — — Ending balance $ (21) $ 17 $ (4) (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 Other Total (in millions, net of income tax) Nine Months Ended September 30, 2018 Beginning balance $ (25) $ 17 $ (8) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $3, respectively) (3) 8 5 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) 3 (3) — Regulatory account transfer (net of taxes of $0 and $2, respectively) 1 (5) (4) Reclassification of stranded income tax to retained earnings (5) — (5) Net current period other comprehensive gain (loss) (4) — (4) Ending balance $ (29) $ 17 $ (12) (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 its GT&S rate case, which generally occur every three or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Electric Revenue from contracts with customers Residential $ 1,557 $ 1,649 $ 3,839 $ 4,023 Commercial 1,481 1,430 3,568 3,737 Industrial 466 448 1,085 1,126 Agricultural 496 523 844 966 Public street and highway lighting 17 18 50 55 Other (1) (82) (273) (391) (388) Total revenue from contracts with customers - electric 3,935 3,795 8,995 9,519 Regulatory balancing accounts (2) (381) (328) 297 211 Total electric operating revenue $ 3,554 $ 3,467 $ 9,292 $ 9,730 Natural gas Revenue from contracts with customers Residential $ 249 $ 242 $ 1,764 $ 1,652 Commercial 92 87 461 402 Transportation service only 264 287 950 847 Other (1) (98) 30 (303) (149) Total revenue from contracts with customers - gas 507 646 2,872 2,752 Regulatory balancing accounts (2) 371 269 222 190 Total natural gas operating revenue 878 915 3,094 2,942 Total operating revenues $ 4,432 $ 4,382 $ 12,386 $ 12,672 (1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Recently Adopted Accounting Standards Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amended the guidance related to the definition of a lease, the recognition of lease assets and liabilities, and the disclosure of key information about leasing arrangements. Under the new standard, a lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility adopted the ASU for leases on January 1, 2019. PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, PG&E Corporation and Utility elected not to separate lease and non-lease components. Additionally, PG&E Corporation and the Utility will not restate comparative reporting periods. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Condensed Consolidated Balance Sheets. Finance leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Condensed Consolidated Balance Sheets. Financing leases were immaterial for the nine months ended September 30, 2019. On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of only the fixed lease payments. This amount is presented within the supplemental disclosures of noncash activities. For the nine months ended September 30, 2019, the Utility made total cash payments, including fixed and variable, of $1.79 billion for operating leases which are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Condensed Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Condensed Consolidated Statement of Cash Flows. The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. At September 30, 2019, the Utility’s leases had a weighted average remaining lease term of 6.1 years and a weighted average discount rate of 6.1%. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease fixed cost $ 266 $ 502 Operating lease variable cost 669 1,468 Total operating lease costs $ 935 $ 1,970 The following table shows the Utility’s future expected operating lease payments: (in millions) September 30, 2019 2019 (1) $ 184 2020 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,981 Less imputed interest (554) Total $ 2,427 (1) Represents the remaining expected operating lease payments from October 1, 2019 through December 31, 2019. The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361 Accounting Standards Issued But Not Yet Adopted Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements , which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326), which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.

REGULATORY ASSETS, LIABILITIES,

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	9 Months Ended
	Sep. 30, 2019
Regulated Operations [Abstract]
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Long-Term Regulatory Assets Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2019 December 31, 2018 Pension benefits (1) $ 1,918 $ 1,947 Environmental compliance costs 1,067 1,013 Utility retained generation (2) 239 274 Price risk management 140 90 Unamortized loss, net of gain, on reacquired debt 66 76 Catastrophic event memorandum account (3) 954 790 Wildfire expense memorandum account (4) 143 94 Fire hazard prevention memorandum account (5) 294 263 Fire risk mitigation memorandum account (6) 109 — Wildfire mitigation plan memorandum account (7) 160 — Deferred income taxes (8) 94 — Other (9) 527 417 Total long-term regulatory assets $ 5,711 $ 4,964 (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. Recovery of CEMA costs are subject to CPUC review and approval. (4) Includes specific incremental wildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are 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 are subject to CPUC review and approval. (6) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs are subject to CPUC review and approval. (7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through September 30, 2019. Recovery of WMPMA costs are subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) September 30, 2019 balance includes $178 million of unamortized debt issuance costs and debt discount that was written off in March 2019 to present the debt subject to compromise at the outstanding face value. Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2019 December 31, 2018 Cost of removal obligations (1) $ 6,341 $ 5,981 Deferred income taxes — 283 Recoveries in excess of AROs (3) 462 356 Public purpose programs (4) 802 674 Employee benefit plans (5) 428 421 Other 1,303 824 Total long-term regulatory liabilities $ 9,336 $ 8,539 (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. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2019 December 31, 2018 Electric distribution $ 148 $ 160 Electric transmission 43 128 Utility generation 93 79 Gas distribution and transmission 454 462 Energy procurement 739 168 Public purpose programs 137 111 Other 305 327 Total regulatory balancing accounts receivable $ 1,919 $ 1,435 Payable Balance at (in millions) September 30, 2019 December 31, 2018 Electric transmission $ 125 $ 134 Gas distribution and transmission 24 9 Energy procurement 545 59 Public purpose programs 612 587 Other 349 287 Total regulatory balancing accounts payable $ 1,655 $ 1,076 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

DEBT

DEBT	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
DEBT	DEBT Debtor-In-Possession Facilities In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court. On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement. Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case. On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, following the Bankruptcy Court’s final approval of the DIP Facilities, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and repaid the $350 million outstanding under the DIP Revolving Facility. The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. Debtor-in-Possession Financing The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at September 30, 2019: (in millions) Termination Aggregate Limit Term Loan Borrowings Revolver Letters of Credit Outstanding Aggregate DIP Facilities December 2020 (1) $ 5,500 $ 1,500 $ — $ 599 $ 3,401 (1) May be extended to December 2021, subject to satisfaction of certain terms and conditions, including payment of a 25 basis point extension fee. As of September 30, 2019, PG&E Corporation and the Utility each had no commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases. Debt The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise: Balance at (in millions) Contractual Interest Rates September 30, 2019 December 31, 2018 Debt Subject to Compromise (1) PG&E Corporation Borrowings under Pre-Petition Credit Facility PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 variable rate (2) $ 300 $ 300 Other borrowings Term Loan - Stated Maturity: 2020 variable rate (3) 350 350 Total PG&E Corporation Debt Subject to Compromise 650 650 Utility Senior Notes - Stated Maturity: 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 2.45% 400 400 2023 3.25% to 4.25% 1,175 1,175 2024 through 2047 2.95% to 6.35% 14,600 14,600 Unamortized discount, net of premium and debt issuance costs — (178) Total Senior notes, net of premium and debt issuance costs 17,525 17,347 Pollution Control Bonds - Stated Maturity: Series 2008 F and 2010 E, due 2026 (4) 1.75% 100 100 Series 2009 A-B, due 2026 (5) variable rate (6) 149 149 Series 1996 C, E, F, 1997 B due 2026 (5) variable rate (7) 614 614 Total pollution control bonds 863 863 Borrowings under Pre-Petition Credit Facilities Utility Revolving Credit Facilities - Stated Maturity: 2022 (8) variable rate (9) 2,888 2,965 Other borrowings: Term Loan - Stated Maturity: 2019 variable rate (10) 250 250 Total Borrowings under Pre-Petition Credit Facility Subject to Compromise 3,138 3,215 Total Utility Debt Subject to Compromise 21,526 21,425 Total PG&E Corporation Consolidated Debt Subject to Compromise $ 22,176 $ 22,075 (1) Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Utility Debt Subject to Compromise does not include $287 million of accrued contractual interest to the Petition Date. At March 31, 2019, PG&E Corporation and the Utility wrote off $178 million of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Condensed Consolidated Balance Sheets. See Notes 2 and 4 for further details. (2) At September 30, 2019, the contractual LIBOR-based interest rate on loans was 3.49%. (3) At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.22%. (4) Pollution Control Bonds series 2008F and 2010E were reissued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (5) Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility. (6) At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 8.20%. (7) At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 8.20% to 8.33%. (8) At September 30, 2019, excludes $23 million of undrawn letters of credit. (9) At September 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.29%. (10) At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 2.62%. Debt Commitments See “Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitments Letters” in Note 2 of the Condensed Consolidated Financial Statements above for discussion of the debt commitments.

EQUITY

EQUITY	9 Months Ended
	Sep. 30, 2019
Equity [Abstract]
EQUITY	EQUITY There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the nine months ended September 30, 2019. PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans. During the nine months ended September 30, 2019, 8.9 million shares were issued for cash proceeds of $85 million under these plans. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation. 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, due to the uncertainty related to the causes of and potential liabilities associated with the Northern California wildfires. See Wildfire-related Contingencies in Note 10 below. The DIP Credit Agreement includes usual and customary covenants for debtor-in-possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, declare and pay any dividend or make any other distributions with respect to any of their capital stock. Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s wildfire mitigation plan. PG&E Corporation does not expect to pay any cash dividends during the Chapter 11 Cases.

EARNINGS PER SHARE

EARNINGS PER SHARE	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE PG&E Corporation’s basic EPS are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2019 2018 2019 2018 Income (Loss) attributable to common shareholders $ (1,619) $ 564 $ (4,039) $ 22 Weighted average common shares outstanding, basic 529 517 528 516 Add incremental shares from assumed conversions: Employee share-based compensation — — — 1 Weighted average common shares outstanding, diluted 529 517 528 517 Total income (loss) per common share, diluted $ (3.06) $ 1.09 $ (7.65) $ 0.04 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

DERIVATIVES

DERIVATIVES	9 Months Ended
	Sep. 30, 2019
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. By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices. 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 counter-party. 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 September 30, 2019 December 31, 2018 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 186,320,892 177,750,349 Options 32,310,000 13,735,405 Electricity (Megawatt-hours) Forwards, Futures and Swaps 8,270,404 3,833,490 Congestion Revenue Rights (3) 316,273,308 340,783,089 (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 September 30, 2019, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 46 $ — $ 41 $ 87 Other noncurrent assets – other 170 — — 170 Current liabilities – other (29) — 3 (26) Noncurrent liabilities – other (140) — 1 (139) Total commodity risk $ 47 $ — $ 45 $ 92 At December 31, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 44 $ (1) $ 89 $ 132 Other noncurrent assets – other 165 — — 165 Current liabilities – other (29) 1 7 (21) Noncurrent liabilities – other (90) — 2 (88) Total commodity risk $ 90 $ — $ 98 $ 188 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 2,687 $ — $ — $ — $ 2,687 Nuclear decommissioning trusts Short-term investments 17 — — — 17 Global equity securities 1,913 — — — 1,913 Fixed-income securities 876 738 — — 1,614 Assets measured at NAV — — — — 19 Total nuclear decommissioning trusts (2) 2,806 738 — — 3,563 Price risk management instruments (Note 8) Electricity — 3 201 27 231 Gas — 12 — 14 26 Total price risk management instruments — 15 201 41 257 Rabbi trusts Fixed-income securities — 100 — — 100 Life insurance contracts — 74 — — 74 Total rabbi trusts — 174 — — 174 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 140 Total long-term disability trust 5 — — — 145 TOTAL ASSETS $ 5,498 $ 927 $ 201 $ 41 $ 6,826 Liabilities: Price risk management instruments (Note 8) Electricity $ — $ — $ 167 $ (4) $ 163 Gas — 2 — — 2 TOTAL LIABILITIES $ — $ 2 $ 167 $ (4) $ 165 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $502 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,593 $ — $ — $ — $ 1,593 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 1,793 — — — 1,793 Fixed-income securities 661 639 — — 1,300 Assets measured at NAV — — — — 16 Total nuclear decommissioning trusts (2) 2,483 639 — — 3,138 Price risk management instruments (Note 8) Electricity — 5 203 51 259 Gas — 1 — 37 38 Total price risk management instruments — 6 203 88 297 Rabbi trusts Fixed-income securities — 93 — — 93 Life insurance contracts — 67 — — 67 Total rabbi trusts — 160 — — 160 Long-term disability trust Short-term investments 7 — — — 7 Assets measured at NAV — — — — 155 Total long-term disability trust 7 — — — 162 TOTAL ASSETS $ 4,083 $ 805 $ 203 $ 88 $ 5,350 Liabilities: Price risk management instruments (Note 8) Electricity $ 4 $ 5 $ 108 $ (10) $ 107 Gas — 2 — — 2 TOTAL LIABILITIES $ 4 $ 7 $ 108 $ (10) $ 109 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $408 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. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the three and nine months ended September 30, 2019 and 2018. Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the 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 Sensitivity Analysis The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 8 above.) Fair Value at (in millions) September 30, 2019 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 190 $ 60 Market approach CRR auction prices (15.62) - 9.48 Power purchase agreements $ 11 $ 107 Discounted cash flow Forward prices 13.28 - 62.12 (1) Represents price per megawatt-hour. Fair Value at (in millions) December 31, 2018 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input Range (1) Congestion revenue rights $ 203 $ 75 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 33 Discounted cash flow Forward prices $ 19.81 - 38.80 (1) Represents price per megawatt-hour. Level 3 Reconciliation The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2019 and 2018: Price Risk Management Instruments (in millions) 2019 2018 Asset balance as of July 1 $ 109 $ 34 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (75) (10) Asset balance as of September 30 $ 34 $ 24 (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) 2019 2018 Asset balance as of January 1 $ 95 $ 42 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (61) (18) Asset balance as of September 30 $ 34 $ 24 (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 September 30, 2019 and December 31, 2018, as they are short-term in nature. The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2019 At December 31, 2018 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation (1) $ — $ — $ 350 $ 350 Utility (1)(2) 1,500 1,503 17,450 14,747 (1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation and the Utility became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. (2) The fair value of the Utility pre-petition debt is $18.4 billion as of September 30, 2019. For more information, see Note 2 and Note 5. Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) As of September 30, 2019 Amortized Total Unrealized Gains Total Unrealized Losses Total Fair Nuclear decommissioning trusts Short-term investments $ 17 $ — $ — $ 17 Global equity securities 488 1,449 (5) 1,932 Fixed-income securities 1,508 108 (2) 1,614 Total (1) $ 2,013 $ 1,557 $ (7) $ 3,563 As of December 31, 2018 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 568 1,246 (5) 1,809 Fixed-income securities 1,288 30 (18) 1,300 Total (1) $ 1,885 $ 1,276 $ (23) $ 3,138 (1) Represents amounts before deducting $502 million and $408 million for the periods ended September 30, 2019 and December 31, 2018, 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) September 30, 2019 Less than 1 year $ 49 1–5 years 508 5–10 years 390 More than 10 years 667 Total maturities of fixed-income securities $ 1,614 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 346 $ 319 $ 808 $ 1,121 Gross realized gains on securities 45 3 67 51 Gross realized losses on securities (5) (5) (12) (14)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES	9 Months Ended
	Sep. 30, 2019
Wildfires Related Contingencies
Loss Contingencies [Line Items]
WILDFIRE-RELATED CONTINGENCIES	WILDFIRE-RELATED CONTINGENCIESPG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Wildfire-Related Claims Wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. At September 30, 2019 and December 31, 2018, the Utility’s Condensed Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims as follows: Balance at (in millions) September 30, 2019 December 31, 2018 2015 Butte fire $ 212 $ 226 2017 Northern California wildfires (1) 7,492 3,500 2018 Camp fire (1) 12,856 10,500 Total wildfire-related claims (2) $ 20,560 $ 14,226 (1) Wildfire-related claims as of September 30, 2019 are shown net of $100 million of funds deposited into the Wildfire Assistance Fund on August 2, 2019 in connection with potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires. This $100 million is allocated to wildfire-related claims as follows: $30 million to the 2017 Northern California wildfires and $70 million to the 2018 Camp fire. For a description of the other components and categories of claims related to this liability accrual, see “Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual.” (2) On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. On August 16, 2019, the Bankruptcy Court issued the Lift Stay Decision in which it granted the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to allow a state court jury trial to proceed regarding the Tubbs fire. See “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” below. In addition, during the three and nine months ended September 30, 2019, the Utility incurred legal and other costs of $25 million and $57 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and nine months ended September 30, 2019, the Utility incurred legal and other costs of $13 million and $54 million, respectively, related to the 2017 Northern California wildfires, as compared to $53 million and $120 million, respectively, in the same periods in 2018. 2018 Camp Fire Background On November 8, 2018, a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of October 25, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website. On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release: • Cal Fire determined that the 2018 Camp fire was caused by electrical transmission lines owned and operated by the Utility near Pulga, California. • Cal Fire identified a second ignition site and stated that the second fire was consumed by the original fire which started earlier near Pulga, California. Cal Fire stated that the cause of the second fire was determined to be “vegetation into electrical distribution lines owned and operated by” the Utility. Cal Fire indicated in its news release that its investigation report for the 2018 Camp fire has been forwarded to the Butte County District Attorney. The California Attorney General’s Office is also investigating the 2018 Camp fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, Cal Fire’s investigation report has not been released publicly. PG&E Corporation and the Utility accept Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire. Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in areas impacted by the 2018 Camp fire. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities may also be investigating the fire. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete. 2017 Northern California Wildfires Background Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities. Cal Fire has investigated the causes of the 2017 Northern California wildfires and made the following determinations: • the Utility’s equipment was involved in causing 20 wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket, Atlas, Cascade, Pressley, Point and Youngs fires); and • the Tubbs fire was caused by a private electrical system adjacent to a residential structure. For additional details regarding Cal Fire’s investigations and findings, see PG&E Corporation’s and the Utility’s joint quarterly report on Form 10-Q for the period ended June 30, 2019. As described under the heading “District Attorneys’ Offices’ Investigations” below, certain of the 2017 Northern California wildfires were the subject of criminal investigations, which have been settled or resulted in PG&E Corporation and the Utility being informed by the applicable district attorneys’ office of a decision not to prosecute. The SED also conducted investigations into whether the Utility committed civil violations in connection with the 2017 Northern California wildfires. See “Order Instituting an Investigation into the 2017 Northern California Wildfires” in Note 11 for a description of these proceedings, including the alleged violations in connection with 2017 Northern California wildfires. Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete. Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, 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, including in connection with SB 901.) In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent. Further, the Utility could be subject to material fines, penalties, or restitution orders if the CPUC or any law enforcement agency were to bring an enforcement action, including a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which sought to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. However, on August 16, 2019, the Bankruptcy Court issued an order granting the TCC’s motion to lift the stay on the 2017 Tubbs fire to allow a state court jury trial for certain preference plaintiffs, as further described under the heading “Proceeding in San Francisco Superior Court for Certain Tubbs Fire-Related Claims” below. Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, insurance carriers have filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation and the Utility entered into a RSA with certain holders of insurance subrogation claims to potentially resolve all insurance subrogation claims relating to the 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process. Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process. As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. On October 18, 2019, the TCC filed with the Bankruptcy Court a motion for entry of an order extending the Bar Date for individual wildfire-related claims. On October 28, 2019, PG&E Corporation and the Utility announced that they had offered to extend the Bar Date for individual wildfire-related claims from October 21, 2019 to December 20, 2019. On the same day, during a meet and confer between PG&E Corporation and the Utility and the TCC, and at the request of the TCC, PG&E Corporation and the Utility agreed to further extend the Bar Date for individual wildfire-related claims to December 31, 2019. On November 4, 2019, PG&E Corporation and the Utility and the TCC announced that they have reached agreement to an extension of the Bar Date for individual wildfire-related claims to December 31, 2019, which agreement also involves procedures for additional notice to potential individual wildfire claimants. PG&E Corporation and the Utility and the TCC will file a stipulation with the Bankruptcy Court detailing the terms of the agreement and seeking approval of their agreement. PG&E Corporation and the Utility have received numerous proofs of claim in connection with the 2018 Camp fire and the 2017 Northern California wildfires since the Petition Date and are early in the process of reconciling those claims to the amounts listed in the schedules of assets and liabilities. See “Potential Claims” in Note 2 above. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and the 2017 Northern California wildfires. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigations. PG&E Corporation and the Utility and wildfire litigation plaintiffs have reached an agreement to transfer available evidence collected by Cal Fire for the fires for which its investigation reports have been released to a shared storage facility. The transfer of the evidence is not yet complete. (See “District Attorneys’ Offices’ Investigations” below for information regarding certain investigations related to the 2018 Camp fire and 2017 Northern California wildfires.) Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be resolved through the Chapter 11 process, the state court proceedings related to the 2017 Tubbs fire, regulatory proceedings and any potential enforcement proceedings. The timing and outcome of these and other potential proceedings are uncertain. As discussed under the headings “Plan Support Agreements with Public Entities” and “Restructuring Support Agreement with Holders of Subrogation Claims,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims as well as with certain insurance subrogation claimholders to potentially resolve all wildfire-related insurance subrogation claims. As discussed under the heading “Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual,” PG&E Corporation and the Utility have been engaged from time to time in discussions with representatives of individual wildfire claimholders to potentially resolve their claims. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with any other claimholders. On October 25, 2019, PG&E Corporation and the Utility submitted a brief to the Bankruptcy Court challenging the application of inverse condemnation to California’s investor-owned utilities, including the Utility. The UCC joined in PG&E Corporation’s and the Utility’s brief, and a group of PG&E Corporation’s shareholders filed a supporting supplemental statement. Opposition briefs are due on November 15, 2019, and the Bankruptcy Court will hear argument regarding PG&E Corporation’s and the Utility’s motion on November 19, 2019. Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims (the “Tubbs Trial”) On July 2, 2019, the TCC filed a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order modifying the automatic stay to permit certain individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire, and to request the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires to order one or more of the cases of these individual plaintiffs to trial with preference pursuant to California Code of Civil Procedure section 36. On July 9, 2019, the TCC submitted an amended motion to request relief from the stay with respect to additional individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire. On July 3, 2019, the Ad Hoc Subrogation Group submitted a motion for relief from the automatic stay to permit certain of the Ad Hoc Subrogation Group’s members to pursue their claims against PG&E Corporation and the Utility regarding the issue of PG&E Corporation’s and the Utility’s liability for the Tubbs fire in the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires. On August 16, 2019, the Bankruptcy Court issued the Lift Stay Decision in which it granted the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to allow a state court jury trial to proceed regarding the Tubbs fire. On September 12, 2019, the San Francisco County Superior Court issued a tentative ruling, granting motions for the Tubbs fire trial to proceed with respect to all designated individual plaintiffs on a preferential fast-track basis and denying PG&E Corporation’s and the Utility’s motion to transfer the trial from San Francisco County to Sonoma County, which the San Francisco County Superior Court reaffirmed on September 16, 2019, and set trial to begin on January 7, 2020. At a status conference held on October 1, 2019, a pre-trial schedule was established, including dates relating to fact and expert discovery, motions in limine and jury selection. The court further ordered that the trial would be bifurcated into two phases – a liability phase to be tried first, followed, if necessary, by a damages phase. The court scheduled the trial to last for eight weeks, with four weeks for liability and four weeks for damages. The court further stated that it tentatively agreed with the plaintiffs’ argument that the same jury should hear both phases of the trial. On October 7, 2019, PG&E Corporation and the Utility notified the court and the plaintiffs that PG&E Corporation and the Utility would consent to a single jury for both phases of the preference trial. Also on October 7, 2019, PG&E Corporation and the Utility filed a motion for a protective order against publicity seeking to prevent plaintiffs’ counsel from communicating with members of the news media concerning specific evidence or theories of liability. The plaintiffs filed oppositions to the motion on October 17, 2019. Oral argument on the motion was held on October 30, 2019, during which the court directed the parties to further meet and confer on the issue and report back to the court for continued hearing on November 8, 2019. Discovery is ongoing. The ultimate outcome of this proceeding is uncertain and could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California (the “Estimation Proceeding”) On July 18, 2019, PG&E Corporation and the Utility filed a motion for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. On August 21, 2019, the Bankruptcy Court issued recommendations to the District Court recommending the District Court order the partial withdrawal of the reference of the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire and the 2017 Northern California wildfires. On August 23, 2019, the District Court issued an order adopting the recommendation of the Bankruptcy Court in full and ordering that the reference to the Bankruptcy Court be withdrawn in part. Accordingly, the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire is expected to take place before the District Court (and not the Bankruptcy Court). On October 9, 2019, the District Court issued an initial order setting the estimation hearing for February 18, 2020 and reserving two weeks for the hearing, with the possibility of an additional week if warranted. In the order, the District Court named the TCC and PG&E Corporation and the Utility as the lead participants in the estimation proceedings. With respect to the subject matter of the estimation proceedings, the District Court proposed to “factor in the uncertainty of the liability disputes by directing the parties to assess the probability that the claimants would be successful at trial.” The parties will continue to meet and confer on those issues. In terms of potential damages, the parties agree that the District Court will estimate losses for property, personal injury (including emotional distress and mental and physical health impairments), wrongful death and punitive damages (if any). On October 11, 2019, the District Court issued a Scheduling Order. According to the Scheduling Order, fact discovery is to be completed by December 23, 2019, expert discovery is to be completed by February 6, 2020, parties’ opening briefs are due February 12, 2020, and the first day of hearing is set for February 18, 2020. The ultimate outcome of this proceeding is uncertain and could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Plan Support Agreements with Public Entities On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). For more information on the PSAs, see “Plan Support Agreements with Public Entities” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of PG&E Corporation and the Utility’s joint Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019. Restructuring Support Agreement with Holders of Subrogation Claims On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with the Consenting Subrogation Creditors of insurance subrogation claims. On November 1, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors of insurance subrogation claims entered into an amended and restated Restructuring Support Agreement. The RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle the Subrogation Claims, upon the terms and conditions set forth in the RSA. Under the RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the RSA. The RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Proposed Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Proposed Plan in the Chapter 11 Cases. The effectiveness of the RSA is conditioned upon approval of the Bankruptcy Court in accordance with the terms of the RSA by no later than November 14, 2019 (which date may be extended with the consent of the holders of at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors). The RSA will automatically terminate if (i) the Proposed Plan is not confirmed by June 30, 2020 (or such later date as may be authorized by any amendment to AB 1054) or (ii) the Effective Date does not occur prior to December 31, 2020 (or six months following the deadline for confirmation of the Proposed Plan if such deadline is extended by any amendment to AB 1054). The RSA may be terminated by any Consenting Subrogation Creditor as to itself if the Aggregate Subrogation Recovery is modified. The RSA may be terminated by the Consenting Subrogation Creditors holding at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors under certain circumstances, including, among others, if (i) they reasonably determine in good faith at any time prior to confirmation of the Proposed Plan that PG&E Corporation and the Utility are insolvent or otherwise unable to raise sufficient capital to pay the Aggregate Subrogation Recovery on the Effective Date, (ii) PG&E Corporation and the Utility breach the terms of the RSA or otherwise fail to take certain actions specified in the RSA, (iii) the Proposed Plan does not treat the individual plaintiffs’ wildfire-related claims consistent with the provisions of AB 1054, (iv) the Bankruptcy Court allows a plan proponent other than PG&E Corporation and the Utility to commence soliciting votes on a plan (other than the Proposed Plan) that incorporates the terms of the settlement contemplated by the RSA and PG&E Corporation and the Utility have not already commenced soliciting votes on the Proposed Plan which incorporates such settlement, (v) the Bankruptcy Court confirms a plan other than the Proposed Plan or (vi) the Proposed Plan is modified to be inconsistent with such settlement. The RSA may be terminated by PG&E Corporation and the Utility (a) in the event of certain breaches of the RSA by Consenting Subrogation Creditors holding at least 5% of the Subrogation Claims held by Consenting Subrogation Creditors or (b) if the Bankruptcy Court confirms a plan other than the Proposed Plan or if the terms of the Proposed Plan related to the settlement contemplated by the RSA become unenforceable or are enjoined. Subject to certain limited exceptions, the aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) will survive any termination of the RSA and will be binding on PG&E Corporation and the Utility in the Chapter 11 Cases. On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the RSA and approving the terms of the settlement contemplated under the RSA. Pursuant to that motion, PG&E Corporation and the Utility requested that the allowance of the Subrogation Claims in the aggregate amount of $11.0 billion be effective upon the approval of the motion and that the treatment and satisfaction of the Subrogation Claims be effectuated pursuant to the Proposed Plan following confirmation of the effectiveness of the Proposed Plan. Various stakeholders filed objections to PG&E Corporation’s and the Utility’s motion, including the UCC, the Ad Hoc Noteholder Committee, the TCC and the U.S. Government. A hearing on PG&E Corporation’s and the Utility’s motion to approve the RSA was held on October 23, 2019, at which the Bankruptcy Court continued the hearing on the motion to November 1

OTHER CONTINGENCIES AND COMMITM

OTHER CONTINGENCIES AND COMMITMENTS	9 Months Ended
	Sep. 30, 2019
Other Contingencies and Commitments
Loss Contingencies [Line Items]
OTHER CONTINGENCIES AND COMMITMENTS	OTHER CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters. Enforcement and Litigation Matters U.S. District Court Matters and Probation On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis. On November 27, 2018, the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018. On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the 2017 Atlas fire. The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order. On January 4, 2019, the court issued another order requiring that the Utility provide, “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition. The responses of the Utility were submitted on January 10, 2019. On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire. In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to: • prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,” • “document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and • at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.” The Utility was ordered to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed. The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019. On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Mitigation Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019. On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to: • “fully comply with all applicable laws concerning vegetation management and clearance requirements;” • “fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;” • submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;” • “maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and • “ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forgo issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.” The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.” Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond five years in light of the violation that has been adjudicated and whether the Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue. The court held a sentencing hearing on the probation violation related to reporting requirements in connection with the 2017 Honey fire on May 7, 2019. After that hearing, the court imposed two additional conditions of probation by order dated May 14, 2019: (1) requiring that PG&E Corporation’s Board of Directors, Chief Executive Officer, senior executives, the Monitor and U.S. Probation Officer visit the towns of Paradise and San Bruno “to gain a firsthand understanding of the harm inflicted on those communities;” and (2) requiring that a committee of PG&E Corporation’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Mitigation Plan and the additional terms of probation regarding wildfire safety, reporting in writing to the full Board at least quarterly. The court also stated that it was not going to rule at this time on whether the court has authority to extend probation and would leave that question “in abeyance.” The court did not discuss whether the Monitor reports should be made public. Members of PG&E Corporation’s Board of Directors and senior management attended site visits to the Town of Paradise on June 7, 2019 and the City of San Bruno on July 16, 2019, which were coordinated by the U.S. Probation Officer overseeing the Utility’s probation. In addition, the Compliance and Public Policy Committee, a committee of PG&E Corporation’s Board of Directors, will be responsible for tracking the Utility’s progress against the Utility’s wildfire mitigation plan, as approved by the CPUC, and compliance with the terms of the Utility’s probation regarding wildfire safety. On July 10, 2019, the court ordered the Utility to respond to a Wall Street Journal article titled “PG&E Knew for Years Its Lines Could Spark Wildfires, and Didn’t Fix Them” on a paragraph-by-paragraph basis, stating the extent to which each paragraph in the article is accurate. The court also ordered the Utility to disclose all political contributions made by the Utility since January 1, 2017, and provide additional explanations regarding those contributions and dividends distributed prior to filing the Chapter 11 Cases. The Utility filed its response with the court on July 31, 2019. In the response, the Utility disagreed with the Wall Street Journal article’s suggestion that the Utility knew of the specific maintenance conditions that caused the 2018 Camp fire and nonetheless deferred work that would have addressed those conditions. On July 26, 2019, the Monitor submitted a letter to the court regarding its VM field inspections (“VM inspections”), which were designed to evaluate the Utility’s compliance with aspects of its publicly-filed Wildfire Mitigation Plan’s EVM. The Monitor’s letter, which was filed on the public docket on August 14, 2019, provided its preliminary observations and preliminary findings, which included that (1) the Utility’s contractors had missed trees that should have been identified and worked under the EVM program; and (2) the Utility’s systems for recording, tracking and assigning EVM work were inconsistent and may have been contributing to the missed work. In its September 3, 2019 response to the Monitor’s letter, the Utility detailed its plan to address the concerns raised by the Monitor. The Monitor’s concerns and the Utility’s response were discussed at a hearing on September 17, 2019. During the September 17, 2019 hearing, the court asked the Utility to provide information about: (1) its preparation for high wind season; and (2) the number of fires 10 acres or greater allegedly caused by the Utility to date in 2019. The Utility responded on October 1, 2019 by describing its efforts to strengthen its programs and infrastructure to maximize safety and mitigate the potential wildfire risk during high wind season. The Utility also responded that as of September 17, 2019, the Utility’s equipment may have contributed to nine ignitions in 2019 that resulted in fires 10 acres or greater. Two of these fires were potentially caused by vegetation and one was potentially caused by equipment. On October 2, 2019, the court asked the Utility for further information regarding the three fires potentially caused by vegetation and equipment. In its response, which was filed on October 9, 2019, the Utility provided information regarding certain fires, including but not limited to total acreage of the fire, ignition date, and potential causes. On October 8, 2019, the court held a hearing related to the Utility’s San Bruno community service. An additional related hearing is scheduled for November 12, 2019. On October 14, 2019, the court issued a request for information in connection with the PSPS event the Utility initiated on October 9, 2019 that shut off power to approximately 738,000 customers in 34 counties across Northern and Central California, asking the Utility to file a statement setting forth, among other information, “how many trees and limbs fell or blew onto the deenergized lines and how many of those would likely have caused arcing had the power been left on.” The Utility’s response was filed on October 30, 2019. On November 4, 2019, the court issued a request for information in connection with PSPS events the Utility initiated in late October of 2019, asking the Utility to file a statement setting forth, among other information, the same type of information requested on October 14, 2019 in connection with the PSPS event initiated on October 9, 2019. The Utility’s response is due on November 29, 2019. CPUC and FERC Matters OII into the 2017 Northern California Wildfires On June 27, 2019, the CPUC issued an OII (the “2017 Northern California Wildfires OII”) to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.” The 2017 Northern California Wildfires OII discloses the findings of a June 13, 2019 report by the SED, which, among other things, alleges that the Utility committed 27 violations in connection with 12 of the 2017 Northern California wildfires (specifically, the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphur and Youngs fires). As described in the OII, the 27 alleged violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizing a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identified by the SED in connection with the Cherokee, La Porte and Tubbs fires. The 37 fire was determined by the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential. On a status conference call before the assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal charges in connection with the Lobo and McCourtney fires, the SED may add alleged violations related to those fires and the 2018 Camp fire to the OII. The 2017 Northern California Wildfires OII required the Utility to (i) show cause by July 29, 2019 why it should not be sanctioned for the 27 violations alleged in the SED report and (ii) submit a report by August 5, 2019, responding to information requests relating to “matters of concern that […] warrant further investigation and possible charges for violations of law.” These latter matters include the following: (i) the Utility’s vegetation management procedures and practices, (ii) the Utility’s procedures and practices regarding use of “recloser” devices in fire risk areas and during fire season, (iii) the Utility’s lack of procedures or policies for proactive de-energization of power lines during times of extreme fire danger, and (iv) the Utility’s record-keeping and other practices. The Utility was also required to take certain corrective actions and provide information regarding the qualifications of vegetation management personnel within 30 days of the issuance of the 2017 Northern California Wildfires OII. The Utility was required to also file an application to develop an open source, publicly available asset management system/database and mobile app, the costs of development and continued operation of which would be at shareholder expense. As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violations set forth in the OII. The Utility also filed a Corrective Actions Report and an Application to Develop a Mobile Application and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019, the Utility submitted a report to respond to the information requests contained in the OII, as explained above. On October 9, 2019, the SED disclosed investigation reports, which, among other things, allege that the Utility committed five violations in connection with the Lobo and McCourtney fires. On October 17, 2019, the SED filed a motion to add the alleged violations related to the Lobo and McCourtney fires to the OII. The Utility does not intend to oppose the motion. The SED has disclosed that its investigation report for the 2018 Camp fire may be available by mid-November 2019. It is uncertain when the SED will file a motion to add alleged violations related to the 2018 Camp fire to the OII. The assigned ALJ has scheduled evidentiary hearings in the OII to take place on December 9-13, 2019. The Utility, SED, PAO, CUE, TURN, OSA, Mendocino and Sonoma Counties, Napa County, City and County of San Francisco, the City of Santa Rosa, and Thomas Del Monte have continued to engage in multilateral settlement discussions. The parties have not reached a settlement but have agreed to continue to engage in settlement discussions. The OII will continue to follow its procedural schedule. Based on the information currently available, PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties, including fines or other remedies, on the Utility. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties. The Utility is unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to pay a material amount of penalties or if the Utility were required to incur a material amount of costs that it cannot recover through rates. This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed. OII and Order to Show Cause into the Utility ’ s Locate and Mark practices On December 14, 2018, the CPUC issued an order instituting investigation and order to show cause (the “OII”) to assess the Utility’s practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the CPUC should not find violations in this matter, and why the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner. The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided an analysis, based on the available data, of tickets that should be properly categorized as late, and identification of associated dig-ins. As a result, the OII will determine whether the Utility violated any provision of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locate and mark policies, practices, and related issues, and the extent to which the Utility’s practices with regard to locate and mark may have diminished system safety. The CPUC indicates that it has not concluded that the Utility has violated the law in any instance pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found, the CPUC will consider what monetary fines and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines. On March 14, 2019, as directed by the CPUC, the Utility submitted a report that addressed the SED report and responded to the order to show cause. A prehearing conference was held on April 4, 2019, to establish scope and a procedural schedule. The assigned commissioner and ALJ encouraged the SED and the Utility to engage in settlement discussions. On April 24, 2019, the Utility provided notice of a settlement conference and the parties began ongoing settlement discussions. On May 7, 2019, the assigned commissioner issued a scoping memo and ruling that included within the proceedings, in addition to the issues identified in the OII relating to the Utility’s locate and mark procedures, issues relating to locating and marking of the Utility’s electric distribution facilities and the use of “qualified electrical workers” for locating and marking underground infrastructure. On July 24, 2019, the SED submitted its opening testimony to the CPUC. A status conference with the ALJ was held on July 30, 2019. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony was submitted on August 16, 2019, and the Utility’s reply testimony was submitted on September 18, 2019. On October 3, 2019, the Utility, SED and CUE jointly submitted to the CPUC a proposed settlement agreement and jointly moved for its approval. The following parties have participated in the settlement negotiations but have not joined the settlement: PAO, TURN, OSA, and the City and County of San Francisco. The proposed settlement will be reviewed by the ALJ overseeing the proceeding, and these other parties will have an opportunity to provide comments on the proposed settlement agreement before a final CPUC decision is issued. On October 11, 2019, PAO, TURN, and OSA indicated that they intend to provide comments on the proposed settlement agreement. Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $65 million, comprised of (i) a fine of $5 million funded by shareholders to be paid to the General Fund of the State of California pursuant to, and in accordance with, the time frame and other provisions governing distributions as set forth in the Chapter 11 plan of reorganization for the Utility as confirmed by the Bankruptcy Court; and (ii) $60 million in shareholder-funded initiatives undertaken to enhance, among other things, the Utility’s locate and mark compliance and capabilities and the reliability of the Underground Service Alert ticket management information that the Utility maintains in the ordinary course of its business. In accordance with the settlement agreement, shareholder-funded system enhancements will include, among other things, locate and mark ticket compliance audits to verify accurate categorization of timeliness, compliance audits using field reviews of gas and electric locate and mark tickets to assess performance, procedure adherence and compliance, and additional locate and mark staff. The expenditure of any sums not fully expended within three years of the effective date of the settlement agreement will be subject to further agreement among the parties. The Utility expects that the system enhancement spending pursuant to this settlement agreement will occur through 2022. The settlement agreement will become effective upon: (i) approval by the CPUC in a written decision and (ii) following such approval by the CPUC, approval by the Bankruptcy Court. The CPUC may accept, reject or modify the terms of the settlement agreement, including imposing additional penalties on the Utility. On October 4, 2019, the ALJ issued a ruling modifying the procedural schedule to focus the evidentiary hearings on the proposed settlement agreement. An evidentiary hearing was held on October 21, 2019; comments on the settlement agreement were submitted by certain other parties on November 4, 2019, and reply comments are due November 19, 2019. As of September 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $5 million accrual for the amounts payable to the General Fund of the State of California. Because the CPUC has wide discretion and there are a number of factors that can be considered in determining penalties, the Utility is unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to pay a material amount of penalties beyond the amount reserved, or if the Utility were required to incur a material amount of costs that it cannot recover through rates. This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed. For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. OII into Compliance with Ex Parte Communication Rules On April 26, 2018, the CPUC approved the revised PD issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the “settlement agreement”) by the Utility, the Cities of San Bruno and San Carlos, PAO, the SED, and TURN. The decision resulted in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above. As a result of the CPUC’s April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At September 30, 2019, the Utility has refunded $24 million for a portion of the 2019 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred. The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On June 28, 2019, the Cities of San Bruno and San Carlos, PAO, the SED, TURN, and the Utility filed a joint motion with the CPUC seeking approval of a comprehensive settlement agreement that addresses all issues in the second phase of this proceeding. The phase two settlement agreement proposed that the Utility pay a total penalty of $10 million comprised of: (1) a $2 million payment to the California General Fund, (2) forgoing collection of $5 million in revenue requirements during the term of its 2019 GT&S rate case, (3) forgoing collection of $1 million in revenue requirement during the term of its 2020 GRC cycle, and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $2 million ($1 million to each city). According to the terms of the phase two settlement, these payments and forgone collection would not take place until a plan of reorganization is approved in the Chapter 11 Cases. In accordance with accounting rules, adjustments related to forgone collections would be recorded in the periods in which they are incurred. As of September 30, 2019, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $4 million accrual for the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos. On September 20, 2019, the CPUC extended the statutory deadline until December 31, 2019 to review the phase two settlement agreement and to prepare a proposed decision. The Utility is unable to predict whether the CPUC will approve the settlement. For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. Transmission Owner Rate Case Revenue Subject to Refund The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 went into effect on May 1, 2019. On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. The Utility expects the FERC to issue a decision in the TO18 rate case by late-2019, however, that decision will likely be the subject of requests for rehearing and appeal. On September 21, 2018, the Utility filed an all-party settlement with FERC, which was approved by FERC on December 20, 2018, in co

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2019
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS 2019 Kincade Fire On October 23, 2019, 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 6, 2019, 7:00 p.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres and was 100% contained. In the incident update, Cal Fire reported 0 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). On October 23, 2019, by 3 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. On October 24, 2019, the Utility submitted an electric incident report to the CPUC indicating that: • at approximately 9:20 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; • 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. The cause of the 2019 Kincade fire is under investigation by Cal Fire and the CPUC, and PG&E Corporation and the Utility are cooperating with their investigations. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information contained in the electric incident report and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is reasonably possible that they will incur a loss in connection with the 2019 Kincade fire. However, due to the limited amount of time that has elapsed since the start of the 2019 Kincade fire, the preliminary stages of the investigations, lack of access to potentially relevant evidence and the uncertainty as to the cause of the fire and the extent and magnitude of potential damages, PG&E Corporation and the Utility cannot reasonably estimate the amount or range of such possible loss. While the cause of the 2019 Kincade fire remains under investigation and there are a number of unknown facts surrounding the cause of the 2019 Kincade fire, the Utility could be subject to significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on the bankruptcy timing and process and the ability of the Utility to participate in the Wildfire Fund. Impact of Recent and Future Public Safety Power Shutoffs On October 9, 2019, the Utility initiated a PSPS event which was the subject of significant criticism, including from the California Governor and the CPUC. In connection with this PSPS event, the California Governor suggested that PG&E Corporation and the Utility provide affected customers an automatic credit or rebate of $100 per residential customer and $250 per small business, to be funded by PG&E Corporation’s and the Utility’s shareholders. On October 29, 2019, PG&E Corporation and the Utility announced that they would issue such credits to customers with respect to the October 9, 2019 PSPS event. PG&E Corporation and the Utility estimate that such credit will result in an approximately $90 million charge for the fourth quarter of 2019. As of the date of this filing, PG&E Corporation and the Utility do not expect to issue any similar customer credits in connection with any other PSPS events (whether past events or in the future). If PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future), the aggregate amount of any such credits or rebates could be substantial and could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. On October 28, 2019, the CPUC announced that it would open a formal investigation of 2019 PSPS events, utility compliance with CPUC regulations and requirements, any resulting violations, and potential actions to ensure utilities are held accountable. The CPUC will meet on November 13, 2019 to discuss initiating an investigation into whether California's investor-owned electric utilities prioritized safety and complied with the CPUC’s regulations and requirements with respect to their October 2019 PSPS events. The purpose of this investigation would be to investigate whether California’s investor-owned utilities’ actions to de-energize their electric facilities during hazardous weather conditions properly balance the need to provide reliable service with public safety. In later phases of this proceeding, the CPUC may consider taking action if violations of the CPUC’s decisions or general orders have been committed and to enforce compliance, if necessary. PG&E Corporation and the Utility are unable to predict the timing and outcome of such an investigation.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2019
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 as 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, 2018 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2018 Form 10-K.  This quarterly report should be read in conjunction with the 2018 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, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, pension and other post-retirement benefit plan obligations, and the valuation of LSTC. 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 and results of operations during the period in which such change occurred
Variable Interest Entities	Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. 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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2019, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights 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 September 30, 2019, 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.
Pension and Other Postretirement Plans	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 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 its GT&S rate case, which generally occur every three or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted	Recently Adopted Accounting Standards Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amended the guidance related to the definition of a lease, the recognition of lease assets and liabilities, and the disclosure of key information about leasing arrangements. Under the new standard, a lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility adopted the ASU for leases on January 1, 2019. PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, PG&E Corporation and Utility elected not to separate lease and non-lease components. Additionally, PG&E Corporation and the Utility will not restate comparative reporting periods. The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking. Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Condensed Consolidated Balance Sheets. Finance leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Condensed Consolidated Balance Sheets. Financing leases were immaterial for the nine months ended September 30, 2019. On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of only the fixed lease payments. This amount is presented within the supplemental disclosures of noncash activities. For the nine months ended September 30, 2019, the Utility made total cash payments, including fixed and variable, of $1.79 billion for operating leases which are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Condensed Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Condensed Consolidated Statement of Cash Flows. The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements. At September 30, 2019, the Utility’s leases had a weighted average remaining lease term of 6.1 years and a weighted average discount rate of 6.1%. The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease fixed cost $ 266 $ 502 Operating lease variable cost 669 1,468 Total operating lease costs $ 935 $ 1,970 The following table shows the Utility’s future expected operating lease payments: (in millions) September 30, 2019 2019 (1) $ 184 2020 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,981 Less imputed interest (554) Total $ 2,427 (1) Represents the remaining expected operating lease payments from October 1, 2019 through December 31, 2019. The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361 Accounting Standards Issued But Not Yet Adopted Fair Value Measurement In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements , which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures. Intangibles—Goodwill and Other In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures. Financial Instruments—Credit Losses In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326), which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.
Earnings Per Share	PG&E Corporation’s basic EPS are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Use of Derivative Instruments	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. By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices. 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 counter-party. 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. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the three and nine months ended September 30, 2019 and 2018. Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the 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 liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

BANKRUPTCY FILING (Tables)

BANKRUPTCY FILING (Tables)	9 Months Ended
	Sep. 30, 2019
Reorganizations [Abstract]
Schedule of Liabilities Subject to Compromise	The following table presents LSTC as reported in the Condensed Consolidated Balance Sheets at September 30, 2019: (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Financing debt (2) $ 21,813 $ 650 $ 22,463 Wildfire-related claims (3) 20,560 — 20,560 Trade creditors 1,253 6 1,259 Non-qualified benefit plan 18 126 144 2001 bankruptcy disputed claims 221 — 221 Customer deposits & advances 278 — 278 Other 166 2 168 Total Liabilities Subject to Compromise $ 44,309 $ 784 $ 45,093 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. (2) At September 30, 2019, PG&E Corporation and the Utility had $650 million and $21,526 million in aggregate principal amount of pre-petition indebtedness, respectively. Utility pre-petition financing debt also includes $287 million of accrued contractual interest to the Petition Date. See Note 5 for details of pre-petition debt reported as LSTC. (3) See Note 10 for information regarding pre-petition wildfire-related claims reported as LSTC, including the settlement with the Consenting Subrogation Creditors entered into on September 22, 2019. Wildfire-related claims include amounts for the Butte fire of $212 million and is shown net of $100 million deposited into the Wildfire Assistance Fund on August 2, 2019 in connection with potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires.
Schedule of Debtor Reorganization Items	Reorganization items, net for the three months ended September 30, 2019 and from the Petition Date through September 30, 2019 include the following: Three Months Ended September 30, 2019 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ — $ — $ — Legal and other 83 7 90 Interest income (14) (3) (17) Adjustments to LSTC — — — Total reorganization items, net $ 69 $ 4 $ 73 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility. Petition Date Through September 30, 2019 (in millions) Utility PG&E Corporation (1) PG&E Corporation Consolidated Debtor-in-possession financing costs $ 97 $ 17 $ 114 Legal and other 181 10 191 Interest income (41) (8) (49) Adjustments to LSTC — — — Total reorganization items, net $ 237 $ 19 $ 256 (1) PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2019
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 nine months ended September 30, 2019 and 2018 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2019 2018 2019 2018 Service cost for benefits earned (1) $ 110 $ 128 $ 14 $ 16 Interest cost 189 171 19 17 Expected return on plan assets (226) (255) (31) (33) Amortization of prior service cost (1) (1) 3 4 Amortization of net actuarial loss 1 1 — (1) Net periodic benefit cost 73 44 5 3 Regulatory account transfer (2) 10 41 — — Total $ 83 $ 85 $ 5 $ 3 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (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 Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Service cost for benefits earned (1) $ 332 $ 385 $ 42 $ 49 Interest cost 568 515 57 52 Expected return on plan assets (679) (766) (92) (98) Amortization of prior service cost (4) (4) 10 11 Amortization of net actuarial loss 2 4 (2) (4) Net periodic benefit cost 219 134 15 10 Regulatory account transfer (2) 31 118 — — Total $ 250 $ 252 $ 15 $ 10 (1) A portion of service costs are capitalized pursuant to ASU 2017-07.
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) are summarized below: Pension Other Total (in millions, net of income tax) Three Months Ended September 30, 2019 Beginning balance $ (21) $ 17 $ (4) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) 1 — 1 Regulatory account transfer (net of taxes of $0 and $1, respectively) — (2) (2) Net current period other comprehensive gain (loss) — — — Ending balance $ (21) $ 17 $ (4) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended September 30, 2018 Beginning balance $ (30) $ 17 $ (13) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $0, and $0, respectively) 1 (1) — Regulatory account transfer (net of taxes of $0 and $1, respectively) 1 (2) (1) Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (29) $ 17 $ (12) (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 Other Total (in millions, net of income tax) Nine Months Ended September 30, 2019 Beginning balance $ (21) $ 17 $ (4) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $3, respectively) (3) 7 4 Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) 2 (1) 1 Regulatory account transfer (net of taxes of $1 and $2, respectively) 1 (6) (5) Net current period other comprehensive gain (loss) — — — Ending balance $ (21) $ 17 $ (4) (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 Other Total (in millions, net of income tax) Nine Months Ended September 30, 2018 Beginning balance $ (25) $ 17 $ (8) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $3, respectively) (3) 8 5 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) 3 (3) — Regulatory account transfer (net of taxes of $0 and $2, respectively) 1 (5) (4) Reclassification of stranded income tax to retained earnings (5) — (5) Net current period other comprehensive gain (loss) (4) — (4) Ending balance $ (29) $ 17 $ (12) (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 September 30, Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Electric Revenue from contracts with customers Residential $ 1,557 $ 1,649 $ 3,839 $ 4,023 Commercial 1,481 1,430 3,568 3,737 Industrial 466 448 1,085 1,126 Agricultural 496 523 844 966 Public street and highway lighting 17 18 50 55 Other (1) (82) (273) (391) (388) Total revenue from contracts with customers - electric 3,935 3,795 8,995 9,519 Regulatory balancing accounts (2) (381) (328) 297 211 Total electric operating revenue $ 3,554 $ 3,467 $ 9,292 $ 9,730 Natural gas Revenue from contracts with customers Residential $ 249 $ 242 $ 1,764 $ 1,652 Commercial 92 87 461 402 Transportation service only 264 287 950 847 Other (1) (98) 30 (303) (149) Total revenue from contracts with customers - gas 507 646 2,872 2,752 Regulatory balancing accounts (2) 371 269 222 190 Total natural gas operating revenue 878 915 3,094 2,942 Total operating revenues $ 4,432 $ 4,382 $ 12,386 $ 12,672 (1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers.
Schedule of Lease Expense	The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations: (in millions) Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease fixed cost $ 266 $ 502 Operating lease variable cost 669 1,468 Total operating lease costs $ 935 $ 1,970
Schedule of Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments	The following table shows the Utility’s future expected operating lease payments: (in millions) September 30, 2019 2019 (1) $ 184 2020 679 2021 623 2022 548 2023 255 2024 96 Thereafter 596 Total lease payments 2,981 Less imputed interest (554) Total $ 2,427 (1) Represents the remaining expected operating lease payments from October 1, 2019 through December 31, 2019.
Schedule of Future Minimum Rental Payments for Operating Leases	The following table shows the Utility’s future expected obligations for power purchase and other lease commitments: (in millions) December 31, 2018 2019 $ 684 2020 677 2021 621 2022 546 2023 252 Thereafter 581 Total lease commitments $ 3,361

REGULATORY ASSETS, LIABILITIE_2

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)	9 Months Ended
	Sep. 30, 2019
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2019 December 31, 2018 Pension benefits (1) $ 1,918 $ 1,947 Environmental compliance costs 1,067 1,013 Utility retained generation (2) 239 274 Price risk management 140 90 Unamortized loss, net of gain, on reacquired debt 66 76 Catastrophic event memorandum account (3) 954 790 Wildfire expense memorandum account (4) 143 94 Fire hazard prevention memorandum account (5) 294 263 Fire risk mitigation memorandum account (6) 109 — Wildfire mitigation plan memorandum account (7) 160 — Deferred income taxes (8) 94 — Other (9) 527 417 Total long-term regulatory assets $ 5,711 $ 4,964 (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. Recovery of CEMA costs are subject to CPUC review and approval. (4) Includes specific incremental wildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are 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 are subject to CPUC review and approval. (6) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs are subject to CPUC review and approval. (7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through September 30, 2019. Recovery of WMPMA costs are subject to CPUC review and approval. (8) Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP. (9) September 30, 2019 balance includes $178 million of unamortized debt issuance costs and debt discount that was written off in March 2019 to present the debt subject to compromise at the outstanding face value.
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2019 December 31, 2018 Cost of removal obligations (1) $ 6,341 $ 5,981 Deferred income taxes — 283 Recoveries in excess of AROs (3) 462 356 Public purpose programs (4) 802 674 Employee benefit plans (5) 428 421 Other 1,303 824 Total long-term regulatory liabilities $ 9,336 $ 8,539 (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.
Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2019 December 31, 2018 Electric distribution $ 148 $ 160 Electric transmission 43 128 Utility generation 93 79 Gas distribution and transmission 454 462 Energy procurement 739 168 Public purpose programs 137 111 Other 305 327 Total regulatory balancing accounts receivable $ 1,919 $ 1,435
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) September 30, 2019 December 31, 2018 Electric transmission $ 125 $ 134 Gas distribution and transmission 24 9 Energy procurement 545 59 Public purpose programs 612 587 Other 349 287 Total regulatory balancing accounts payable $ 1,655 $ 1,076

DEBT (Tables)

DEBT (Tables)	9 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Schedule of Debtor-in-Possession Financing	The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at September 30, 2019: (in millions) Termination Aggregate Limit Term Loan Borrowings Revolver Letters of Credit Outstanding Aggregate DIP Facilities December 2020 (1) $ 5,500 $ 1,500 $ — $ 599 $ 3,401
Schedule of Debt	The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise: Balance at (in millions) Contractual Interest Rates September 30, 2019 December 31, 2018 Debt Subject to Compromise (1) PG&E Corporation Borrowings under Pre-Petition Credit Facility PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022 variable rate (2) $ 300 $ 300 Other borrowings Term Loan - Stated Maturity: 2020 variable rate (3) 350 350 Total PG&E Corporation Debt Subject to Compromise 650 650 Utility Senior Notes - Stated Maturity: 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 2.45% 400 400 2023 3.25% to 4.25% 1,175 1,175 2024 through 2047 2.95% to 6.35% 14,600 14,600 Unamortized discount, net of premium and debt issuance costs — (178) Total Senior notes, net of premium and debt issuance costs 17,525 17,347 Pollution Control Bonds - Stated Maturity: Series 2008 F and 2010 E, due 2026 (4) 1.75% 100 100 Series 2009 A-B, due 2026 (5) variable rate (6) 149 149 Series 1996 C, E, F, 1997 B due 2026 (5) variable rate (7) 614 614 Total pollution control bonds 863 863 Borrowings under Pre-Petition Credit Facilities Utility Revolving Credit Facilities - Stated Maturity: 2022 (8) variable rate (9) 2,888 2,965 Other borrowings: Term Loan - Stated Maturity: 2019 variable rate (10) 250 250 Total Borrowings under Pre-Petition Credit Facility Subject to Compromise 3,138 3,215 Total Utility Debt Subject to Compromise 21,526 21,425 Total PG&E Corporation Consolidated Debt Subject to Compromise $ 22,176 $ 22,075 (1) Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Utility Debt Subject to Compromise does not include $287 million of accrued contractual interest to the Petition Date. At March 31, 2019, PG&E Corporation and the Utility wrote off $178 million of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Condensed Consolidated Balance Sheets. See Notes 2 and 4 for further details. (2) At September 30, 2019, the contractual LIBOR-based interest rate on loans was 3.49%. (3) At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.22%. (4) Pollution Control Bonds series 2008F and 2010E were reissued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (5) Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility. (6) At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 8.20%. (7) At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 8.20% to 8.33%. (8) At September 30, 2019, excludes $23 million of undrawn letters of credit. (9) At September 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.29%. (10) At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 2.62%.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Common Shares Outstanding for Calculating Diluted EPS	The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2019 2018 2019 2018 Income (Loss) attributable to common shareholders $ (1,619) $ 564 $ (4,039) $ 22 Weighted average common shares outstanding, basic 529 517 528 516 Add incremental shares from assumed conversions: Employee share-based compensation — — — 1 Weighted average common shares outstanding, diluted 529 517 528 517 Total income (loss) per common share, diluted $ (3.06) $ 1.09 $ (7.65) $ 0.04

DERIVATIVES (Tables)

DERIVATIVES (Tables)	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 December 31, 2018 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 186,320,892 177,750,349 Options 32,310,000 13,735,405 Electricity (Megawatt-hours) Forwards, Futures and Swaps 8,270,404 3,833,490 Congestion Revenue Rights (3) 316,273,308 340,783,089 (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 September 30, 2019, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 46 $ — $ 41 $ 87 Other noncurrent assets – other 170 — — 170 Current liabilities – other (29) — 3 (26) Noncurrent liabilities – other (140) — 1 (139) Total commodity risk $ 47 $ — $ 45 $ 92 At December 31, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 44 $ (1) $ 89 $ 132 Other noncurrent assets – other 165 — — 165 Current liabilities – other (29) 1 7 (21) Noncurrent liabilities – other (90) — 2 (88) Total commodity risk $ 90 $ — $ 98 $ 188
Schedule of Offsetting Liabilities	At September 30, 2019, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Balance Current assets – other $ 46 $ — $ 41 $ 87 Other noncurrent assets – other 170 — — 170 Current liabilities – other (29) — 3 (26) Noncurrent liabilities – other (140) — 1 (139) Total commodity risk $ 47 $ — $ 45 $ 92 At December 31, 2018, the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Netting Cash Collateral Total Derivative Current assets – other $ 44 $ (1) $ 89 $ 132 Other noncurrent assets – other 165 — — 165 Current liabilities – other (29) 1 7 (21) Noncurrent liabilities – other (90) — 2 (88) Total commodity risk $ 90 $ — $ 98 $ 188

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 2,687 $ — $ — $ — $ 2,687 Nuclear decommissioning trusts Short-term investments 17 — — — 17 Global equity securities 1,913 — — — 1,913 Fixed-income securities 876 738 — — 1,614 Assets measured at NAV — — — — 19 Total nuclear decommissioning trusts (2) 2,806 738 — — 3,563 Price risk management instruments (Note 8) Electricity — 3 201 27 231 Gas — 12 — 14 26 Total price risk management instruments — 15 201 41 257 Rabbi trusts Fixed-income securities — 100 — — 100 Life insurance contracts — 74 — — 74 Total rabbi trusts — 174 — — 174 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 140 Total long-term disability trust 5 — — — 145 TOTAL ASSETS $ 5,498 $ 927 $ 201 $ 41 $ 6,826 Liabilities: Price risk management instruments (Note 8) Electricity $ — $ — $ 167 $ (4) $ 163 Gas — 2 — — 2 TOTAL LIABILITIES $ — $ 2 $ 167 $ (4) $ 165 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $502 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements December 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 1,593 $ — $ — $ — $ 1,593 Nuclear decommissioning trusts Short-term investments 29 — — — 29 Global equity securities 1,793 — — — 1,793 Fixed-income securities 661 639 — — 1,300 Assets measured at NAV — — — — 16 Total nuclear decommissioning trusts (2) 2,483 639 — — 3,138 Price risk management instruments (Note 8) Electricity — 5 203 51 259 Gas — 1 — 37 38 Total price risk management instruments — 6 203 88 297 Rabbi trusts Fixed-income securities — 93 — — 93 Life insurance contracts — 67 — — 67 Total rabbi trusts — 160 — — 160 Long-term disability trust Short-term investments 7 — — — 7 Assets measured at NAV — — — — 155 Total long-term disability trust 7 — — — 162 TOTAL ASSETS $ 4,083 $ 805 $ 203 $ 88 $ 5,350 Liabilities: Price risk management instruments (Note 8) Electricity $ 4 $ 5 $ 108 $ (10) $ 107 Gas — 2 — — 2 TOTAL LIABILITIES $ 4 $ 7 $ 108 $ (10) $ 109 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value.
Level 3 Measurements and Sensitivity Analysis	Fair Value at (in millions) September 30, 2019 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 190 $ 60 Market approach CRR auction prices (15.62) - 9.48 Power purchase agreements $ 11 $ 107 Discounted cash flow Forward prices 13.28 - 62.12 (1) Represents price per megawatt-hour. Fair Value at (in millions) December 31, 2018 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input Range (1) Congestion revenue rights $ 203 $ 75 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 33 Discounted cash flow Forward prices $ 19.81 - 38.80 (1) Represents price per megawatt-hour.
Level 3 Reconciliation	The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2019 and 2018: Price Risk Management Instruments (in millions) 2019 2018 Asset balance as of July 1 $ 109 $ 34 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (75) (10) Asset balance as of September 30 $ 34 $ 24 (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) 2019 2018 Asset balance as of January 1 $ 95 $ 42 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (61) (18) Asset balance as of September 30 $ 34 $ 24 (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 debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2019 At December 31, 2018 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation (1) $ — $ — $ 350 $ 350 Utility (1)(2) 1,500 1,503 17,450 14,747 (1) On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation and the Utility became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5. (2) The fair value of the Utility pre-petition debt is $18.4 billion as of September 30, 2019. For more information, see Note 2 and Note 5.
Schedule of Unrealized Gains (Losses) Related to Available-For-Sale Investments	The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) As of September 30, 2019 Amortized Total Unrealized Gains Total Unrealized Losses Total Fair Nuclear decommissioning trusts Short-term investments $ 17 $ — $ — $ 17 Global equity securities 488 1,449 (5) 1,932 Fixed-income securities 1,508 108 (2) 1,614 Total (1) $ 2,013 $ 1,557 $ (7) $ 3,563 As of December 31, 2018 Nuclear decommissioning trusts Short-term investments $ 29 $ — $ — $ 29 Global equity securities 568 1,246 (5) 1,809 Fixed-income securities 1,288 30 (18) 1,300 Total (1) $ 1,885 $ 1,276 $ (23) $ 3,138 (1) Represents amounts before deducting $502 million and $408 million for the periods ended September 30, 2019 and December 31, 2018, 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) September 30, 2019 Less than 1 year $ 49 1–5 years 508 5–10 years 390 More than 10 years 667 Total maturities of fixed-income securities $ 1,614
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 September 30, Nine Months Ended September 30, (in millions) 2019 2018 2019 2018 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 346 $ 319 $ 808 $ 1,121 Gross realized gains on securities 45 3 67 51 Gross realized losses on securities (5) (5) (12) (14)

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES (Tables)	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Environmental Remediation Liability	At September 30, 2019 and December 31, 2018, the Utility’s Condensed Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims as follows: Balance at (in millions) September 30, 2019 December 31, 2018 2015 Butte fire $ 212 $ 226 2017 Northern California wildfires (1) 7,492 3,500 2018 Camp fire (1) 12,856 10,500 Total wildfire-related claims (2) $ 20,560 $ 14,226 (1) Wildfire-related claims as of September 30, 2019 are shown net of $100 million of funds deposited into the Wildfire Assistance Fund on August 2, 2019 in connection with potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires. This $100 million is allocated to wildfire-related claims as follows: $30 million to the 2017 Northern California wildfires and $70 million to the 2018 Camp fire. For a description of the other components and categories of claims related to this liability accrual, see “Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual.” (2) On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. On August 16, 2019, the Bankruptcy Court issued the Lift Stay Decision in which it granted the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to allow a state court jury trial to proceed regarding the Tubbs fire. See “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” below.

OTHER CONTINGENCIES AND COMMI_2

OTHER CONTINGENCIES AND COMMITMENTS (Tables)	9 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Environmental Remediation Liability	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) September 30, 2019 December 31, 2018 Topock natural gas compressor station $ 382 $ 369 Hinkley natural gas compressor station 143 146 Former manufactured gas plant sites owned by the Utility or third parties (1) 586 520 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 115 111 Fossil fuel-fired generation facilities and sites (3) 116 137 Total environmental remediation liability $ 1,342 $ 1,283 (1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor and Outside East Harbor, Napa, Beach Street, San Francisco North Beach. (2) Primarily driven by the Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant.

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Details)	9 Months Ended
	Sep. 30, 2019segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

BANKRUPTCY FILING (Narrative) (

BANKRUPTCY FILING (Narrative) (Details)	Oct. 11, 2019USD ($)	Sep. 23, 2019USD ($)	Sep. 30, 2019USD ($)structure	Sep. 30, 2019USD ($)structure	Oct. 17, 2019USD ($)	Sep. 22, 2019USD ($)	Jan. 31, 2019USD ($)
Debt Instrument [Line Items]
Amount to be paid for Subrogation Claims Settlement		$ 11,000,000,000
Subrogation claims, professional fees						$ 55,000,000
Compensation fund, maximum amount		8,400,000,000
Settlement claims payment		1,000,000,000
Equity offering - maximum			$ 14,000,000,000	$ 14,000,000,000
Reorganization, weighted average earning base rate			0.95	0.95
Reorganization, weighted average earnings			$ 48,000,000,000	$ 48,000,000,000
Aggregate liability for prepetition wildfire related claims, maximum			$ 18,900,000,000	$ 18,900,000,000
Number of days for effective date for confirmation order				60 days
Maximum number of structures that can be destroyed in wildfire in 2019 | structure			500	500
Asserted administrative expense claims, maximum			$ 250,000,000	$ 250,000,000
Maximum number of structures that can be destroyed in wildfire in 2020 | structure			500	500
Plan of reorganization, Wildfire Claim Cap, pending RSA		$ 17,900,000,000
Backstop commitment, initial commitment premium ( percentage)			0.0075	0.0075
Contractual interest expense on prepetition liabilities not recorded in financial statements			$ 666,000,000
Subsequent event
Debt Instrument [Line Items]
Debt commitment letters, required equity funding	$ 14,000,000,000
Debt commitment letters, required equity funding, preferred equity	2,000,000,000
Plan on reorganization, TCC Ad Hoc Noteholder Plan, proposed plan value					$ 14,500,000,000
Plan of reorganization, TCC Ad Hoc Noteholder Plan, Amount set aside in separate trust					1,000,000,000
Plan of reorganization, TCC Adhoc Noteholder Plan, proposed common stock issuance towards claims, value					$ 12,750,000,000
Plan of reorganization, TCC Adhoc Noteholder Plan, common stock issuable, percentage of post-emergence stock					40.60%
Plan of reorganization, TCC Adhoc Noteholder Plan, proposed common stock issuance for investors, value					$ 15,500,000,000
Plan of reorganization, TCC Adhoc Noteholder Plan, proposed common stock issuance for investors, percentage of post-emergence stock					59.30%
Bridge Loan | Subsequent event
Debt Instrument [Line Items]
Bridge financing facility - maximum	$ 34,350,000,000
Debt instrument, term (in days)	364 days
Bridge Loan | Secured debt | Subsequent event
Debt Instrument [Line Items]
Bridge financing facility - maximum	$ 27,350,000,000
Bridge Loan | Unsecured debt | Subsequent event
Debt Instrument [Line Items]
Bridge financing facility - maximum	$ 7,000,000,000
Unsecured debt | Subsequent event
Debt Instrument [Line Items]
Proposed debt issuance					$ 5,750,000,000
DIP Credit Agreement | Line of Credit | Secured debt
Debt Instrument [Line Items]
Amount arranged							$ 5,500,000,000
Pacific Gas & Electric Co
Debt Instrument [Line Items]
Payments for reorganization items				$ 145,000,000
Pacific Gas & Electric Co | Secured debt | Subsequent event
Debt Instrument [Line Items]
Proposed debt issuance					$ 8,000,000,000
PG&E Corporation
Debt Instrument [Line Items]
Payments for reorganization items				$ 13,000,000
Commitments to April 30, 2020
Debt Instrument [Line Items]
Backstop commitment, additional commitment premium			1.25%	1.25%
Commitments to June 30, 2020
Debt Instrument [Line Items]
Backstop commitment, additional commitment premium			2.50%	2.50%
Commitments to August 29, 2020
Debt Instrument [Line Items]
Backstop commitment, additional commitment premium			0.50%	0.50%

BANKRUPTCY FILING (Schedule of

BANKRUPTCY FILING (Schedule of Liabilities Subject to Compromise) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Aug. 02, 2019	Dec. 31, 2018
Reorganizations [Line Items]
Financing debt	$ 22,463
Wildfire-related claims	20,560
Trade creditors	1,259
Non-qualified benefit plan	144
2001 bankruptcy disputed claims	221
Customer deposits & advances	278
Other	168
Total Liabilities Subject to Compromise	45,093		$ 0
Wildfire-related claims	0		14,226
2018 Camp Fire and 2017 Northern California Wildfires
Reorganizations [Line Items]
Wildfire-related claims	100	$ 105
Pacific Gas & Electric Co
Reorganizations [Line Items]
Financing debt	21,813
Wildfire-related claims	20,560
Trade creditors	1,253
Non-qualified benefit plan	18
2001 bankruptcy disputed claims	221
Customer deposits & advances	278
Other	166
Total Liabilities Subject to Compromise	44,309		0
Aggregate principal amount of debt subject to compromise	21,526
Accrued contractual interest subject to compromise	287
Wildfire-related claims	0		14,226
Pacific Gas & Electric Co | 2015 Butte fire
Reorganizations [Line Items]
Loss contingency liability	212		$ 226
PG&E Corporation
Reorganizations [Line Items]
Financing debt	650
Wildfire-related claims	0
Trade creditors	6
Non-qualified benefit plan	126
2001 bankruptcy disputed claims	0
Customer deposits & advances	0
Other	2
Total Liabilities Subject to Compromise	784
Aggregate principal amount of debt subject to compromise	$ 650

BANKRUPTCY FILING (Schedule o_2

BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($) $ in Millions	3 Months Ended		8 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2019	Sep. 30, 2018
Reorganizations [Line Items]
Debtor-in-possession financing costs	$ 0		$ 114
Legal and other	90		191
Interest income	(17)		(49)
Adjustments to LSTC	0		0
Total reorganization items, net	73	$ 0	256	$ 256	$ 0
PG&E Corporation
Reorganizations [Line Items]
Debtor-in-possession financing costs	0		17
Legal and other	7		10
Interest income	(3)		(8)
Adjustments to LSTC	0		0
Total reorganization items, net	4		19
Utility
Reorganizations [Line Items]
Debtor-in-possession financing costs	0		97
Legal and other	83		181
Interest income	(14)		(41)
Adjustments to LSTC	0		0
Total reorganization items, net	$ 69	$ 0	$ 237	$ 237	$ 0

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 110	$ 128	$ 332	$ 385
Interest cost	189	171	568	515
Expected return on plan assets	(226)	(255)	(679)	(766)
Amortization of prior service cost	(1)	(1)	(4)	(4)
Amortization of net actuarial loss	1	1	2	4
Net periodic benefit cost	73	44	219	134
Regulatory account transfer	10	41	31	118
Total	83	85	250	252
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	14	16	42	49
Interest cost	19	17	57	52
Expected return on plan assets	(31)	(33)	(92)	(98)
Amortization of prior service cost	3	4	10	11
Amortization of net actuarial loss	0	(1)	(2)	(4)
Net periodic benefit cost	5	3	15	10
Regulatory account transfer	0	0	0	0
Total	$ 5	$ 3	$ 15	$ 10

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 10,594	$ 19,061	$ 12,903	$ 19,472
Net current period other comprehensive gain (loss)	0	1	0	(4)
Ending balance	8,991	19,696	8,991	19,696
Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	1	0	(4)
Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	0	0	0
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(4)	(13)	(4)	(8)
Ending balance	(4)	(12)	(4)	(12)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(21)	(30)	(21)	(25)
Ending balance	(21)	(29)	(21)	(29)
Accumulated Other Comprehensive Income (Loss) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	17	17	17
Ending balance	17	17	17	17
Amortization of prior service cost
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	2	4	5
Amortization of prior service cost | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(1)	(3)	(3)
Amount attributable to tax	0	0	1	1
Amortization of prior service cost | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	3	7	8
Amount attributable to tax	1	1	3	3
Amortization of net actuarial loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	0	1	0
Amortization of net actuarial loss | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	1	2	3
Amount attributable to tax	0	0	0	1
Amortization of net actuarial loss | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	(1)	(1)	(3)
Amount attributable to tax	0	0	1	1
Regulatory account transfer
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(1)	(5)	(4)
Regulatory account transfer | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	1	1	1
Amount attributable to tax	0	0	1	0
Regulatory account transfer | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(2)	(6)	(5)
Amount attributable to tax	$ 1	$ 1	$ 2	2
Reclassification of stranded income tax to retained earnings
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				(5)
Reclassification of stranded income tax to retained earnings | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				(5)
Reclassification of stranded income tax to retained earnings | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				$ 0

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Pipeline replacement costs	$ 237	$ 237
Cash payments arising from operating leases		1,790
ROU assets	2,435	2,435
Lease liabilities	$ 2,427	$ 2,427
Weighted average remaining lease term	6 years 1 month 6 days	6 years 1 month 6 days
Weighted average discount rate	6.10%	6.10%
Period for probable revenue recovery		24 months
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
ROU assets			$ 2,800
Lease liabilities			$ 2,800
Pacific Gas & Electric Co
Lessee, Lease, Description [Line Items]
Pipeline replacement costs	$ 237	$ 237
ROU assets	$ 2,427	$ 2,427

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Revenue from contracts with customers
Total operating revenues	$ 4,432	$ 4,382	$ 12,386	$ 12,672
Electric
Revenue from contracts with customers
Total revenue from contracts with customers	3,935	3,795	8,995	9,519
Regulatory balancing accounts	(381)	(328)	297	211
Total operating revenues	3,554	3,467	9,292	9,730
Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,557	1,649	3,839	4,023
Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,481	1,430	3,568	3,737
Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	466	448	1,085	1,126
Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	496	523	844	966
Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	17	18	50	55
Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	(82)	(273)	(391)	(388)
Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	507	646	2,872	2,752
Regulatory balancing accounts	371	269	222	190
Total operating revenues	878	915	3,094	2,942
Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	249	242	1,764	1,652
Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	92	87	461	402
Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	264	287	950	847
Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ (98)	$ 30	$ (303)	$ (149)

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2019
Accounting Policies [Abstract]
Operating lease fixed cost	$ 266	$ 502
Operating lease variable cost	669	1,468
Total operating lease costs	$ 935	$ 1,970

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Future Expected Operating Lease Payments
2019	$ 184
2020	679
2021	623
2022	548
2023	255
2024	96
Thereafter	596
Total lease payments	2,981
Less imputed interest	(554)
Total	$ 2,427
Future Expected Obligations and Other Lease Commitments
2019		$ 684
2020		677
2021		621
2022		546
2023		252
Thereafter		581
Total lease commitments		$ 3,361

REGULATORY ASSETS, LIABILITIE_3

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 5,711	$ 4,964
Retained generation asset costs		1,200
Debtor reorganization items, write-off of debt issuance costs and debt discounts	$ 178
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets		1,918	1,947
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets		1,067	1,013
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets		239	274
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets		140	90
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets		66	76
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets		954	790
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets		143	94
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets		294	263
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets		109	0
Wild fire mitigation plan memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets		160	0
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets		527	417
Deferred income taxes
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 94	$ 0

REGULATORY ASSETS, LIABILITIE_4

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 9,336	$ 8,539
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	6,341	5,981
Deferred income taxes
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	0	283
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	462	356
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	802	674
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	428	421
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,303	$ 824

REGULATORY ASSETS, LIABILITIE_5

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,919	$ 1,435
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	148	160
Total regulatory balancing accounts receivable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	43	128
Total regulatory balancing accounts receivable | Utility generation
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	93	79
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	454	462
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	739	168
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	137	111
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	305	327
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1,655	1,076
Total regulatory balancing accounts payable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	125	134
Total regulatory balancing accounts payable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	24	9
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	545	59
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	612	587
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 349	$ 287

DEBT (Debtor In Possession ("DI

DEBT (Debtor In Possession ("DIP") Facilities and Financing) (Details)	Sep. 30, 2019USD ($)	Apr. 03, 2019USD ($)	Mar. 27, 2019USD ($)	Feb. 01, 2019USD ($)	Jan. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Debtor-in-possession financing	$ 1,500,000,000					$ 0
Commercial paper	0
Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Debtor-in-possession financing	1,500,000,000					0
Commercial paper	0
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged					$ 5,500,000,000
DIP Revolving Facility | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Revolver Borrowings	2,888,000,000					$ 2,965,000,000
Letters of Credit Outstanding	23,000,000
DIP Revolving Facility | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Aggregate Limit	5,500,000,000
Term Loan Borrowings	1,500,000,000
Revolver Borrowings	0
Letters of Credit Outstanding	599,000,000
Aggregate Availability	$ 3,401,000,000
Extension fee (in percentage)	0.25
DIP Revolving Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				$ 3,500,000,000
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Debtor-in-possession financing				1,500,000,000
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged			$ 1,500,000,000
Letters of credit available				750,000,000
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged		$ 1,500,000,000
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				500,000,000
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged				350,000,000
Repayments of debt		$ 350,000,000
DIP Incremental Facilities | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				$ 4,000,000,000

DEBT (Schedule of Long-term Deb

DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt [Line Items]
Debt subject to compromise		$ 22,176	$ 22,075
Debtor reorganization items, write-off of debt issuance costs and debt discounts	$ 178
Pacific Gas & Electric Co
Debt [Line Items]
Debt subject to compromise		21,526	21,425
Borrowings under Pre-Petition Credit Facility		3,138	3,215
Pollution control bonds		863	863
Accrued contractual interest subject to compromise		287
PG&E Corporation
Debt [Line Items]
Debt subject to compromise		650	650
Term Loan - Stated Maturity: 2020 | PG&E Corporation
Debt [Line Items]
Debt subject to compromise		$ 350	350
Interest rate at period end ( in percentage)		3.22%
Pollution Control Bonds - Series 2008 F and 2010 E, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds		$ 100	100
Pollution Control Bonds - Series 2009 A-B, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds		149	149
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds		614	614
Term Loan - Stated Maturity: 2019 | Pacific Gas & Electric Co
Debt [Line Items]
Other borrowings		$ 250	250
Interest rate at period end ( in percentage)		2.62%
Revolving Credit Facility | Pacific Gas & Electric Co
Debt [Line Items]
Borrowings under Pre-Petition Credit Facilities		$ 2,888	2,965
Interest rate at period end ( in percentage)		3.29%
Line of Credit | Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Debt subject to compromise		$ 300	300
Interest rate at period end ( in percentage)		3.49%
Senior Notes | Pacific Gas & Electric Co
Debt [Line Items]
Unamortized discount, net of premium and debt issuance costs		$ 0	(178)
Borrowings under Pre-Petition Credit Facility		17,525	17,347
Senior Notes | Senior Notes Due 2020 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		800	800
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 550	550
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		3.25%
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		4.25%
Senior Notes | Senior Notes Due 2022 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 400	400
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 1,175	1,175
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		3.25%
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		4.25%
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 14,600	$ 14,600
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		2.95%
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates ( in percentage)		6.35%
Letter of Credit | Pollution Control Bonds - Series 2009 A-B, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Interest rate at period end ( in percentage)		8.20%
Letter of Credit | Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Interest rate at period end ( in percentage)		8.20%
Letter of Credit | Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Interest rate at period end ( in percentage)		8.33%

EQUITY (Details)

EQUITY (Details) - 401K Plan and Shared Based Compensation Plans shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)shares
Schedule Of Changes In Equity [Line Items]
Stock issued during period (in shares) | shares	8.9
Cash proceeds from stock issuance | $	$ 85

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Earnings Per Share [Abstract]
Income (Loss) attributable to common shareholders	$ (1,619)	$ 564	$ (4,039)	$ 22
Weighted average common shares outstanding, basic (in shares)	529	517	528	516
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	0	0	0	1
Weighted average common shares outstanding, diluted (in shares)	529	517	528	517
Total income (loss) per common share, diluted (in dollars per share)	$ (3.06)	$ 1.09	$ (7.65)	$ 0.04

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Sep. 30, 2019MMBTUMWh	Dec. 31, 2018MWhMMBTU
Forwards, Futures and Swaps | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	186,320,892	177,750,349
Forwards, Futures and Swaps | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MWh	8,270,404	3,833,490
Options | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	32,310,000	13,735,405
Congestion Revenue Rights | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MWh	316,273,308	340,783,089

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ 47	$ 90
Derivative Asset, Netting	0	0
Cash Collateral	45	98
Total Derivative Balance, Assets	92	188
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	46	44
Derivative Asset, Netting	0	(1)
Cash Collateral	41	89
Total Derivative Balance, Assets	87	132
Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	170	165
Derivative Asset, Netting	0	0
Cash Collateral	0	0
Total Derivative Balance, Assets	170	165
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(29)	(29)
Derivative Liability, Netting	0	1
Cash Collateral	3	7
Total Derivative Balance, Liabilities	(26)	(21)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(140)	(90)
Derivative Liability, Netting	0	0
Cash Collateral	1	2
Total Derivative Balance, Liabilities	$ (139)	$ (88)

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Assets:
Short-term investments	$ 2,687	$ 1,593
Price risk management instruments, netting	41	88
Price risk management instruments, assets	257	297
TOTAL ASSETS	6,826	5,350
Liabilities:
Price risk management instruments, netting	(4)	(10)
TOTAL LIABILITIES	165	109
Amount primarily related to deferred taxes on appreciation of investment value	502	408
Nuclear decommissioning trusts
Assets:
Short-term investments	17	29
Global equity securities	1,913	1,793
Fixed-income securities	1,614	1,300
TOTAL ASSETS	3,563	3,138
Rabbi trusts
Assets:
Fixed-income securities	100	93
Life insurance contracts	74	67
TOTAL ASSETS	174	160
Long-term disability trust
Assets:
Short-term investments	5	7
TOTAL ASSETS	145	162
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	27	51
Price risk management instruments, assets	231	259
Liabilities:
Price risk management instruments, netting	(4)	(10)
Price risk management instruments, liabilities	163	107
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	14	37
Price risk management instruments, assets	26	38
Liabilities:
Price risk management instruments, netting	0	0
Price risk management instruments, liabilities	2	2
Level 1
Assets:
Short-term investments	2,687	1,593
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	5,498	4,083
Liabilities:
TOTAL LIABILITIES	0	4
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	17	29
Global equity securities	1,913	1,793
Fixed-income securities	876	661
TOTAL ASSETS	2,806	2,483
Level 1 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 1 | Long-term disability trust
Assets:
Short-term investments	5	7
TOTAL ASSETS	5	7
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	4
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	15	6
TOTAL ASSETS	927	805
Liabilities:
TOTAL LIABILITIES	2	7
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	738	639
TOTAL ASSETS	738	639
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	100	93
Life insurance contracts	74	67
TOTAL ASSETS	174	160
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	3	5
Liabilities:
Price risk management instruments, gross subject to netting	0	5
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	12	1
Liabilities:
Price risk management instruments, gross subject to netting	2	2
Level 3
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	201	203
TOTAL ASSETS	201	203
Liabilities:
TOTAL LIABILITIES	167	108
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	201	203
Liabilities:
Price risk management instruments, gross subject to netting	167	108
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	19	16
Assets measured at NAV | Long-term disability trust
Assets:
Assets measured at NAV	$ 140	$ 155

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019USD ($)$ / MWh	Dec. 31, 2018USD ($)$ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 6,826	$ 5,350
Liabilities	$ 165	$ 109
Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	(15.62)	(18.61)
Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	9.48	32.26
Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	13.28
Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh		19.81
Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	62.12	38.80
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 190	$ 203
Liabilities	60	75
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	11	0
Liabilities	$ 107	$ 33

FAIR VALUE MEASUREMENTS (Leve_2

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset balance	$ 109	$ 34	$ 95	$ 42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts	(75)	(10)	(61)	(18)
Ending asset balance	$ 34	$ 24	$ 34	$ 24

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 3,138	$ 3,215
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	0	350
Carrying Amount | Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	1,500	17,450
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	0	350
Fair Value | Utility | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	1,503	$ 14,747
Fair value disclosure, pre-petition debt	$ 18,400

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 2,013	$ 1,885
Total Unrealized Gains	1,557	1,276
Total Unrealized Losses	(7)	(23)
Total Fair Value	3,563	3,138
Amount primarily related to deferred taxes on appreciation of investment value	502	408
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	17	29
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	17	29
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	488	568
Total Unrealized Gains	1,449	1,246
Total Unrealized Losses	(5)	(5)
Total Fair Value	1,932	1,809
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,508	1,288
Total Unrealized Gains	108	30
Total Unrealized Losses	(2)	(18)
Total Fair Value	$ 1,614	$ 1,300

FAIR VALUE MEASUREMENTS (Sche_2

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 3,563	$ 3,138
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	49
1–5 years	508
5–10 years	390
More than 10 years	667
Total maturities of fixed-income securities	$ 1,614	$ 1,300

FAIR VALUE MEASUREMENTS (Sche_3

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 346	$ 319	$ 808	$ 1,121
Gross realized gains on securities	45	3	67	51
Gross realized losses on securities	$ (5)	$ (5)	$ (12)	$ (14)

WILDFIRE-RELATED CONTINGENCIE_2

WILDFIRE-RELATED CONTINGENCIES (Summary of Estimated Liabilities) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 20,560	$ 14,226
2015 Butte fire
Loss Contingencies [Line Items]
Total wildfire-related claims	212	226
2017 Northern California wildfires
Loss Contingencies [Line Items]
Total wildfire-related claims	7,492	3,500
2018 Camp Fire
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 12,856	$ 10,500

WILDFIRE-RELATED CONTINGENCIE_3

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Claims Narrative) (Details) - USD ($) $ in Millions	Jun. 18, 2019	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Aug. 02, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Wildfire-related claims		$ 0		$ 0			$ 14,226
Public Entity Wildfire Claims | Settled Litigation
Loss Contingencies [Line Items]
Settlement reached	$ 1,000
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Wildfire-related claims		100		100		$ 105
2017 Northern California wildfires | Public Entity Wildfire Claims | Settled Litigation
Loss Contingencies [Line Items]
Settlement reached				30
2018 Camp Fire | Public Entity Wildfire Claims | Settled Litigation
Loss Contingencies [Line Items]
Settlement reached				70
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Wildfire-related claims		0		0			$ 14,226
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Legal and other costs		13	$ 53	54	$ 120
Pacific Gas & Electric Co | 2018 Camp Fire
Loss Contingencies [Line Items]
Legal and other costs		$ 25		$ 57

WILDFIRE-RELATED CONTINGENCIE_4

WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire Background) (Details) - Pacific Gas & Electric Co - 2018 Camp Fire	Nov. 08, 2018aresidencestructurefatalitybuilding
Loss Contingencies [Line Items]
Number of acres burned (acre) | a	153,336
Number of fatalities (fatality) | fatality	85
Number of residences destroyed (residence) | residence	13,972
Number of commercial structures destroyed (structure) | structure	528
Number of other buildings destroyed (building) | building	4,293

WILDFIRE-RELATED CONTINGENCIE_5

WILDFIRE-RELATED CONTINGENCIES (2017 Northern California Wildfires Background) (Details) a in Thousands	Jan. 04, 2019wildfire	Oct. 30, 2017afatalitystructurewildfire
Loss Contingencies [Line Items]
Number of wildfires (wildfire)	18
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of wildfires (wildfire)		21
Number of acres burned (acre) | a		245
Number of structures destroyed (structure) | structure		8,900
Number of fatalities (fatality) | fatality		44

WILDFIRE-RELATED CONTINGENCIE_6

WILDFIRE-RELATED CONTINGENCIES (Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) - Pending Litigation	Jan. 28, 2019plaintiffcomplaint
Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2018 Camp Fire
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	100
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	4,200
Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court, Classified as Class Action | 2018 Camp Fire
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	9
Complaints Against PG&E Corporation and the Utility in San Francisco Counties Superior Courts | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	750
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	3,800
Lawsuits Against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts, Classified As Class Actions | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	5
Subrogation Complaints Against PG&E Corporation and the Utility in San Francisco County Superior Courts | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	52
Subrogation Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	39

WILDFIRE-RELATED CONTINGENCIE_7

WILDFIRE-RELATED CONTINGENCIES (Plan Support Agreements with Public Entities) (Details) - USD ($) $ in Millions	Sep. 23, 2019	Jun. 18, 2019	Sep. 30, 2019	Sep. 22, 2019
Loss Contingencies [Line Items]
Amount to be paid for Subrogation Claims Settlement	$ 11,000
Subrogation claims, professional fees				$ 55
Public Entity Wildfire Claims | Settled Litigation
Loss Contingencies [Line Items]
Settlement reached		$ 1,000
Public Entity Wildfire Claims | Settled Litigation | 2018 Camp Fire
Loss Contingencies [Line Items]
Settlement reached			$ 70

WILDFIRE-RELATED CONTINGENCIE_8

WILDFIRE-RELATED CONTINGENCIES (Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) insurance_claim in Thousands	May 08, 2019USD ($)	Sep. 06, 2018USD ($)insurance_claim	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2015USD ($)	Oct. 17, 2019USD ($)
2017 Northern California wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers		$ 12,280,000,000
Insurance claims received by insurers (insurance claim) | insurance_claim		55
Statewide insurance claims related to wildfire		$ 10,000,000,000
Loss contingency liability			$ 7,500,000,000		$ 7,500,000,000
2018 Camp Fire
Loss Contingencies [Line Items]
Total insurance claims received by insurers	$ 8,600,000,000
Loss in period			526,000,000	$ 1,900,000,000	2,400,000,000	$ 10,500,000,000
Loss contingency liability			12,900,000,000		12,900,000,000
November 2018 Fires
Loss Contingencies [Line Items]
Total insurance claims received by insurers	$ 12,000,000,000
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers		$ 18,600,000,000
Estimate of possible losses			30,000,000,000		30,000,000,000
2018 Camp Fire and 2017 Northern California Wildfires | Minimum
Loss Contingencies [Line Items]
Total insurance claims received by insurers					30,000,000,000
2018 Camp Fire and 2017 Northern California Wildfires | Maximum
Loss Contingencies [Line Items]
Total insurance claims received by insurers					40,000,000,000
Subsequent event | 2015 Butte Fire, 2017 Northern California Wildfires, and 2018 Camp Fire
Loss Contingencies [Line Items]
Estimate of possible losses								$ 13,500,000,000
Pacific Gas & Electric Co | San Bruno Natural Gas Explosion
Loss Contingencies [Line Items]
Loss in period							$ 1,600,000,000
Loss contingency liability							$ 558,000,000
FEMA | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Amount of claims filed					1,200,000,000
FEMA | 2018 Camp Fire
Loss Contingencies [Line Items]
Amount of claims filed					2,600,000,000
Cal Fire | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Amount of claims filed					133,000,000
Cal Fire | 2018 Camp Fire
Loss Contingencies [Line Items]
Amount of claims filed					110,000,000
OES | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Amount of claims filed					347,000,000
OES | 2018 Camp Fire
Loss Contingencies [Line Items]
Amount of claims filed					2,300,000,000
California Department of Transportation | 2018 Camp Fire
Loss Contingencies [Line Items]
Amount of claims filed					217,000,000
The Ad Hoc Subrogation Group | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Estimate of possible losses			$ 20,000,000,000		$ 20,000,000,000

WILDFIRE-RELATED CONTINGENCIE_9

WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge) (Details) $ in Millions	3 Months Ended				9 Months Ended	12 Months Ended
	Sep. 30, 2019USD ($)wildfire	Jun. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Jun. 30, 2018USD ($)	Sep. 30, 2019USD ($)wildfire	Dec. 31, 2018USD ($)	Oct. 17, 2019USD ($)	Aug. 02, 2019USD ($)
Loss Contingencies [Line Items]
Wildfire-related claims	$ 0		$ 14,226		$ 0	$ 14,226
2018 Camp Fire
Loss Contingencies [Line Items]
Accrued losses	526	$ 1,900			2,400	10,500
Loss contingency liability	12,900				12,900
2017 Northern California wildfires
Loss Contingencies [Line Items]
Loss contingency liability	$ 7,500				$ 7,500
Number of fires with probable losses (wildfire) | wildfire	21				21
Loss from claims related to wildfire	$ 2,000	$ 2,000	$ 1,000	$ 2,500	$ 4,000	$ 3,500
2017 Northern California wildfires | Subsequent event
Loss Contingencies [Line Items]
Wildfire-related claims trust, amount							$ 8,400
2017 Northern California Wildfires, other than Tubbs and 37 Fires
Loss Contingencies [Line Items]
Number of fires with probable losses (wildfire) | wildfire	19				19
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Estimate of possible losses	$ 30,000				$ 30,000
Wildfire-related claims	$ 100				100			$ 105
Loss from claims related to wildfire					20,300
2018 Camp Fire and 2017 Northern California Wildfires, Clean-up and Fire Suppression Costs
Loss Contingencies [Line Items]
Loss from claims related to wildfire					900
2018 Camp Fire and 2017 Northern California Wildfires, Clean-up and Fire Suppression Costs | Subsequent event
Loss Contingencies [Line Items]
Wildfire-related claims trust, amount							900
2015 Butte Fire, 2017 Northern California Wildfires, and 2018 Camp Fire | Subsequent event
Loss Contingencies [Line Items]
Estimate of possible losses							$ 13,500
Subrogated Insurance Claimholders | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					11,000
Professional Service Reimbursement | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					47
Individual Claimholders | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					7,500
Supporting Public Entities | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					$ 1,000

WILDFIRE-RELATED CONTINGENCI_10

WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Jul. 31, 2019	Jul. 08, 2019	Dec. 31, 2018	Jul. 31, 2018
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Liability insurance coverage		$ 1,400			$ 842
Initial self-insured retention per occurrence		10			10
Further retention per occurrence					$ 40
Liability insurance coverage, general liability		700
Liability insurance coverage, property damages		700
Liability insurance coverage, property damages, reinsurance		$ 200
Customer Harm Threshold, potential regulatory adjustment, percentage			20.00%
Customer Harm Threshold, potential regulatory adjustment, percentage of total disallowed wildlife liability			5.00%
2018 Camp Fire
Loss Contingencies [Line Items]
Estimated insurance recoveries	$ 1,380
Insurance settlements receivable	1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Estimated insurance recoveries	842
Insurance settlements receivable	$ 807			$ 829

WILDFIRE-RELATED CONTINGENCI_11

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

WILDFIRE-RELATED CONTINGENCI_12

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation) (Details) - Securities Class Actions Filed in United States District Court for the Northern District of California	Feb. 22, 2019offering	Jun. 30, 2018lawsuit
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit		2
Number of public offerings of notes with complaints against underwriters (offering) | offering	4

WILDFIRE-RELATED CONTINGENCI_13

WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co - Complaints Brought By Butte County District Attorney - Loss from Wildfires $ in Millions	1 Months Ended
	Oct. 31, 2018USD ($)
Loss Contingencies [Line Items]
Settlement agreement term	4 years
Settlement expense	$ 1.5

WILDFIRE-RELATED CONTINGENCI_14

WILDFIRE-RELATED CONTINGENCIES (Clean-up and Repair Costs) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Loss Contingencies [Line Items]
Capital expenditures	$ 981	$ 348
Total long-term regulatory assets	5,711		$ 4,964
Catastrophic event memorandum account
Loss Contingencies [Line Items]
Total long-term regulatory assets	954		790
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Capital expenditures	981	$ 348
Total long-term regulatory assets	5,711		$ 4,964
Pacific Gas & Electric Co | 2018 Camp Fire
Loss Contingencies [Line Items]
Service restoration and repair costs	704
Capital expenditures	270
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Service restoration and repair costs	346
Capital expenditures	171
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2018 Camp Fire
Loss Contingencies [Line Items]
Total long-term regulatory assets	0
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Total long-term regulatory assets	$ 88

WILDFIRE-RELATED CONTINGENCI_15

WILDFIRE-RELATED CONTINGENCIES (Wildfire Assistance Fund) (Details) - USD ($) $ in Millions	Nov. 01, 2019	Sep. 30, 2019	Aug. 02, 2019	Jul. 12, 2019	May 24, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Wildfire-related claims		$ 0				$ 14,226
Disallowance cap, transmission and distribution equity rate base				$ 2,300
Expected wildfire fund allocation metric, initial contribution				$ 4,800
Expected wildfire fund allocation metric, percentage				64.20%
Expected wildfire fund allocation metric, annual contributions				$ 193
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Wildfire-related claims		$ 100	$ 105
Wildfire Assistance Fund, amount sought, portion available for administrative expenses					$ 5
Subsequent event
Loss Contingencies [Line Items]
Claimant payments	$ 22

WILDFIRE-RELATED CONTINGENCI_16

WILDFIRE-RELATED CONTINGENCIES (2015 Butte Fire) (Details) household in Thousands, $ in Millions

Jan. 28, 2019householdplaintiffcomplaintcontractor

Sep. 06, 2018plaintiff

Mar. 02, 2018USD ($)

Mar. 01, 2018USD ($)

Apr. 13, 2017USD ($)

Jan. 29, 2019USD ($)

Nov. 30, 2018USD ($)

May 31, 2017USD ($)

Sep. 30, 2018entitydistrict

Sep. 30, 2019USD ($)

Sep. 30, 2018USD ($)

Dec. 31, 2018USD ($)

May 01, 2018decision

May 23, 2016contractor

Apr. 28, 2016aoutbuildingfatalitystructurehomecomercial_property

Loss Contingencies [Line Items]

Reimbursements

$ 35

$ 64

2015 Butte fire

Loss Contingencies [Line Items]

Payments for claims

$ 14

Insurance settlements receivable

50

$ 85

Reimbursements

35

Pacific Gas & Electric Co

Loss Contingencies [Line Items]

Reimbursements

35

$ 64

Pacific Gas & Electric Co | 2015 Butte fire

Loss Contingencies [Line Items]

Number of acres burned (acre) | a

70,868

Number of fatalities caused by fire (fatality) | fatality

2

Number of homes destroyed by fire (home) | home

549

Number of outbuildings damaged by fire (outbuilding) | outbuilding

368

Number of commercial properties damaged by fire (commercial property) | comercial_property

4

Number of structures damaged (structure) | structure

44

Number of vegetation management contractors (contractor) | contractor

2

Number of complaints filed (complaint) | complaint

95

Number of plaintiffs (plaintiff) | plaintiff

3,900

Number of households represented in court (household) | household

2

Number of vegetation management contractors dismissed from complaints (contractor) | contractor

2

Number of plaintiffs, smaller public entities (plaintiff) | entity

4

Number of plaintiffs, fire districts (plaintiff) | district

3

Fire fighting costs recovery requested

$ 87

Value of claims brought against the company

$ 190

Reasonably possible loss to be incurred

1,100

Loss contingency liability

212

226

Settlement agreement paid

888

Settlement agreements entered

904

Coverage for third party liability

922

Probable insurance recoveries

922

Cumulative reimbursements from insurance policies

60

Insurance settlements receivable

50

$ 85

Reimbursements

35

FEMA | 2015 Butte fire

Loss Contingencies [Line Items]

Amount of claims filed

161

U.S. Department of the Interior | 2015 Butte fire

Loss Contingencies [Line Items]

Amount of claims filed

63

Cal Fire | 2015 Butte fire

Loss Contingencies [Line Items]

Amount of claims filed

105

OES | 2015 Butte fire

Loss Contingencies [Line Items]

Amount of claims filed

$ 107

Agreement Reached in Litigation to Stipulate to Judgment on Inverse Condemnation Grounds | Pacific Gas & Electric Co | 2015 Butte fire

Loss Contingencies [Line Items]

Number of previous appellate courts decisions (decision) | decision

2

Number of plaintiffs in lawsuit (plaintiff) | plaintiff

2

County of Calaveras | Pacific Gas & Electric Co | 2015 Butte fire

Loss Contingencies [Line Items]

Value of claims brought against company

$ 167

$ 85

Settlement reached

$ 25.4

OTHER CONTINGENCIES AND COMMI_3

OTHER CONTINGENCIES AND COMMITMENTS (Enforcement and Litigation Matters) (Details) customer in Thousands, $ in Millions	Jan. 26, 2017USD ($)	Oct. 14, 2019countycustomer	May 14, 2019condition	Jan. 04, 2019wildfire	Aug. 09, 2016count
Loss Contingencies [Line Items]
Number of wildfires (wildfire) | wildfire				18
Pacific Gas & Electric Co | Judicial Ruling | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Number of guilty counts of obstructing a federal agency proceeding					1
Number of guilty counts of violating pipeline integrity management regulations					5
Corporate probation period, term	5 years
Oversight by third-party monitor period, application for early termination, term	3 years
Damages awarded, value | $	$ 3
Number of additional probation conditions (condition) | condition			2
Subsequent event | Potential Power Shut Off
Loss Contingencies [Line Items]
Number of customers | customer		738
Number of counties | county		34

OTHER CONTINGENCIES AND COMMI_4

OTHER CONTINGENCIES AND COMMITMENTS (CPUC and FERC Matters) (Details) $ in Thousands	Sep. 30, 2019USD ($)	Jun. 27, 2019violationwildfire	Sep. 21, 2018	May 17, 2018USD ($)	Apr. 26, 2018USD ($)	Oct. 11, 2019USD ($)	Jun. 30, 2019USD ($)	Jun. 28, 2019USD ($)	Dec. 06, 2018consultant
Loss Contingencies [Line Items]
Settlement agreement, proposed payment to California General Fund								$ 2,000
2017 Northern California wildfires
Loss Contingencies [Line Items]
Loss contingency liability	$ 7,500,000
Ex Parte Communications
Loss Contingencies [Line Items]
Settlement agreement, proposed penalty								10,000
Proposed penalty					$ 97,500
Payment to State General Fund				$ 12,000	12,000
Gas transmission and storage revenue reduction					63,500
2018 GT&S revenue requirement reduction					31,750
2019 GT&S revenue requirement reduction					31,750
Revenue requirement reduction in next GRC cycle					$ 10,000
Payment to city of San Bruno				6,000
Payment to city of San Carlos				$ 6,000
Settlement agreement, proposed forgone revenue collection, 2019 GT&S rate case								5,000
Settlement agreement, proposed forgone revenue collection, 2020 GRC cycle								1,000
Settlement agreement, proposed compensation payments								2,000
Settlement agreement, proposed compensation payments, San Bruno								$ 1,000
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Accrual for GTandS revenue requirement reduction	$ 24,000
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		27
Alleged violations, number of wildfires (wildfire) | wildfire		12
Qualifications of vegetation management personnel, corrective actions, period		30 days
Pacific Gas & Electric Co | Cherokee, La Porte and Tubbs Fires
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0
Pacific Gas & Electric Co | 37 Fire
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0
Pacific Gas & Electric Co | Ex Parte Communications
Loss Contingencies [Line Items]
Loss contingency liability							$ 4,000
Pacific Gas & Electric Co | Pending Litigation | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Number of consultants retained | consultant									2
Electric | Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Requested revenue rate			98.85%
Subsequent event | Pacific Gas & Electric Co | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Settlement agreement, proposed penalty						$ 65,000
Settlement agreement, proposed payment to California General Fund						5,000
Settlement agreement, proposed payment to Shareholders' initiative fund						$ 60,000

OTHER CONTINGENCIES AND COMMI_5

OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Jun. 23, 2016	Dec. 31, 2018
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Accrued legal liabilities		$ 98
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance	$ 696
Permanently disallowed capital	120
Amount subject to audit	$ 576

OTHER CONTINGENCIES AND COMMI_6

OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Topock natural gas compressor station	$ 382	$ 369
Hinkley natural gas compressor station	143	146
Former manufactured gas plant sites owned by the Utility or third parties	586	520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	115	111
Fossil fuel-fired generation facilities and sites	116	137
Total environmental remediation liability	$ 1,342	$ 1,283

OTHER CONTINGENCIES AND COMMI_7

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 998
Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	20,560	$ 14,226
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 207
Topock Site | Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 129
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 621
Remediation cost recovery percentage	90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 91
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 80

OTHER CONTINGENCIES AND COMMI_8

OTHER CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Costs for insurance coverage	$ 212
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Costs for insurance coverage	50
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage	430		$ 1,400
Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	1,000		700
Catastrophic bond reinsurance instrument	10	$ 10
Insurance Coverage for Property Damages
Loss Contingencies [Line Items]
Liability insurance coverage			700
Catastrophic bond reinsurance instrument			$ 200
2018 Camp Fire
Loss Contingencies [Line Items]
Estimated insurance recoveries	1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Estimated insurance recoveries	842
August 1, 2019 - July 31, 2020 | Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	520
September 3, 2019 - September 2, 2020 | Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	$ 480

OTHER CONTINGENCIES AND COMMI_9

OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	$ 41
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	$ 4

OTHER CONTINGENCIES AND COMM_10

OTHER CONTINGENCIES AND COMMITMENTS (Tax Matters) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2019USD ($)
Pacific Gas & Electric Co
Disaggregation of Revenue [Line Items]
Unrecognized tax benefits, decrease resulting from settlements with taxing authorities	$ 10

OTHER CONTINGENCIES AND COMM_11

OTHER CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Billions	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
Recorded unconditional purchase obligation	$ 40

Subsequent Events - 2019 Kincad

Subsequent Events - 2019 Kincade Fire (Details) - 2019 Kincade Fire - Subsequent event	Nov. 06, 2019anumberOfStructuresfatalityinjury	Oct. 23, 2019customer
Subsequent Event [Line Items]
Number of acres burned (acre) | a	77,758
Percentage of fire contained	100.00%
Number of fatalities (fatality) | fatality	0
Number of injuries | injury	4
Number of structures destroyed (structure)	374
Number of residences destroyed (residence)	174
Number of commercial structures destroyed (structure)	11
Number of other buildings destroyed (building)	189
Number of structures damaged (structure)	60
Number of residential structures damaged (structure)	35
Number of commercial structures damaged (structure)	1
Number of other structures damaged (structure)	24
Number of customers without power | customer		27,837

Subsequent Events (Details)

Subsequent Events (Details) - Public Safety Power Shut-offs Event - USD ($)	3 Months Ended
	Dec. 31, 2019	Oct. 09, 2019
Forecast
Subsequent Event [Line Items]
Accrued losses	$ 90,000,000
Subsequent event
Subsequent Event [Line Items]
Automatic credit or rebate, per customer		$ 100
Automatic credit or rebate, per small business		$ 250